EX-99.1 2 exc-20230605ex991.htm EX-99.1
Summer 2023 Investor Meetings

2 Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 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. Any reference to expected average outstanding shares is exclusive of any equity offerings. The factors that could cause actual results to differ materially from the forward-looking statements made by 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) include those factors discussed herein, as well as the items discussed in (1) the Registrants' 2022 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) the Registrants’ First Quarter 2023 Quarterly Report on Form 10-Q (filed on May 3, 2023) in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 12, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. 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). Historical results were revised from amounts previously reported to reflect only Exelon continuing operations. 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 • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and certain excluded items as set forth in the reconciliation 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 (Electric Distribution, Gas Distribution, Transmission). • 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, as management is unable to project all of these items 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 Who is Exelon? (1) Customer count reflects the sum of Exelon’s total gas and electric customer base; Exelon consolidated customer count may not sum due to rounding 1.3 million Electric customers 0.7 million Gas customers 2022 Rate Base: $9.1B Territory: MD Main City: Baltimore Population: 0.6M 4.1 million Electric customers 2022 Rate Base: $19.1B Territory: IL Main City: Chicago Population: 2.7M 0.6 million Electric customers 2022 Rate Base: $3.2B Territory: NJ Main City: Atlantic City Population: 0.1M 1.7 million Electric customers 0.5 million Gas customers 2022 Rate Base: $10.2B Territory: PA Main City: Philadelphia Population: 1.6M 0.5 million Electric customers 0.1 million Gas customers 2022 Rate Base: $3.6B Territory: DE, MD Main City: Wilmington Population: 0.1M 0.9 million Electric customers 2022 Rate Base: $6.1B Territory: MD, DC Main City: Washington, D.C. Population: 0.7M 6 T&D-only utilities Operate within seven regulatory jurisdictions 4 major metro areas served Chicago, Philadelphia, Baltimore, and Washington D.C. 19,100 Employees across our operating companies 10.6 million(1) Electric and gas customers served across our service territories 25,600 Square miles of combined service territory across our jurisdictions 183,540 Circuit miles of electric and gas distribution lines 11,140 Circuit miles of FERC-regulated electric transmission lines $19.1 billion Operating revenues recorded at our utilities in 2022 $56.2 billion Rate base estimate for 2023 $31.3 billion Projected capital investment over 2023 through 2026

5 Premier Utility by Scope and Scale Note: reflects most recent available data as of May 12, 2023 (1) Customer count reflects the sum of Exelon’s total gas and electric customer base. (2) Includes transmission, distribution and generation; represents 2023E rate base projections as disclosed by the companies if available. For companies that do not disclose 2023E, reflects rate base projection calculated from stated growth rate. 10.6 10.1 9.8 8.8 8.5 7.0 6.2 5.9 5.8 5.5 5.2 4.8 4.2 3.0 EXC Peer A Peer B Peer C Peer D Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Peer M $100 $72 $63 $58 $56 $55 $50 $42 $42 $39 $35 $28 $27 Peer A Peer B Peer C Peer D EXC Peer E Peer F Peer G Peer H Peer I Peer J Peer K Peer L Largest Utility by Customers(1) Among the Largest Regulated Utilities by Rate Base(2) Predominantly Regulated T&D Utility Vertically Integrated Utility

6 Delivering Sustainable Value as the Premier T&D Utility Industry-Leading Platform Leading ESG Profile Operational Excellence Financial Discipline Sustainable Value SUSTAINABLE VALUE ✓ Strong Growth Outlook: ~$31.3B of T&D capital from 2023-2026 to meet customer needs, resulting in expected rate base growth of 7.9% and fully regulated T&D operating EPS* growth of 6-8% from 2022-2026(1) ✓ Shareholder Returns: Expect ~60% dividend payout ratio(2) resulting in dividend growing in-line with targeted 6-8% operating EPS* CAGR through 2026 INDUSTRY-LEADING PLATFORM ✓ Size and Scale: Largest T&D utility in the country serving 10+ million customers ✓ Diversified Rate Base: Operate across 7 different regulatory jurisdictions ✓ Large Urban Footprint: Geographically positioned to lead the clean energy buildout in our densely-populated territories OPERATIONAL EXCELLENCE ✓ Safely Powering Reliability and Resilience: Track record of top quartile reliability performance ✓ Delivering a World-Class Customer Experience: Helping customers take control of energy usage while delivering top quartile customer satisfaction results ✓ Constructive Regulatory Environments: ~100% of rate base growth covered by alternative recovery mechanisms and ~73% decoupled from volumetric risk LEADING ESG PROFILE ✓ No Owned Generation Supply: Pure-play T&D utility ✓ Advancing Clean and Affordable Energy Choices: Building a smarter, stronger, and cleaner energy grid with options that meet customer needs at affordable rates ✓ Supporting Communities: Powering the economic health of the diverse communities we serve, while advancing social equity FINANCIAL DISCIPLINE ✓ Strong Balance Sheet: Maintain balance sheet capacity to firmly support investment grade credit ratings ✓ Organic Growth: Reinvestment of free cash to fund utility capital programs with $425M of equity in plan (1) Based off the midpoint of Exelon’s 2022 Adjusted EPS* guidance range of $2.18 - $2.32 as disclosed at Analyst Day in January 2022. (2) Dividend is subject to approval by the Board of Directors.

7 Diverse, Fully Regulated T&D Utility Servicing Large Urban Areas Across Seven Regulatory Jurisdictions Fully Regulated, Transmission and Distribution (1) Represents 2023E rate base. (2) Other includes long-term regulatory assets, which generally earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program. 21% 65% 12% 2% Other(2) Electric Distribution Electric Transmission Gas Delivery ~$56B(1) 29% 21% 20% 18% 5% 4% 3% DC IL FERC Transmission PA MD NJ DE ~$56B(1) Exelon is a fully regulated, majority-electric T&D operator servicing seven different regulatory jurisdictions

8 Best-in-Class Operations Note: reflects 2021 company performance (the latest comparable data set for Exelon and its peers); peer data reflects only a subset (top 10) of the panel of companies that report operational metrics (1) Quartiles are calculated using reported results by the full panel of peer companies that are deemed most comparable to Exelon’s utilities each year; reflects 2020 quartiles to remain consistent with the data used for 2022 benchmarking. (2) Reflects the average number of interruptions per customer reported by Exelon and 20 comparable peer utilities (sources: First Quartile (1QC) T&D, PSE&G Electric Peer Panel Survey, or EIA). (3) Reflects the average time to restore service to customer interruptions reported by Exelon and 20 comparable peer utilities (sources: First Quartile (1QC) T&D, PSE&G Electric Peer Panel Survey, or EIA). (4) Reflects the measurements of perceptions of reliability, customer service, price and management reputation by residential and small business customers reported to Escalent by Exelon and 18 comparable peer utilities. (5) Reflects the percentage of calls responded to in 1 hour or less reported by Exelon and 50 comparable peer utilities (sources: PSE&G Peer Panel Gas Survey and AGA Best Practices Survey). Delivering a World-Class Customer ExperienceIndustry-Leading T&D Operator 0 .5 1 0 .5 7 0 .6 0 0 .6 4 0 .7 1 0 .7 1 0 .9 1 0 .9 4 0 .9 4 0 .9 6 P e e r F E x e lo n P e e r D P e e r G P e e r E P e e r A Top Quartile(1) P e e r B P e e r C P e e r H P e e r I 6 9 7 4 7 7 7 8 8 8 1 0 3 1 0 6 1 0 7 1 0 8 1 1 3 P e e r A P e e r F P e e r C P e e r B E x e lo n P e e r D P e e r E P e e r G P e e r H Top Quartile(1) P e e r I Better Better 2.5 Beta CAIDI(3)2.5 Beta SAIFI(2) 8 .1 9 8 .1 5 P e e r C P e e r B E x e lo n 8 .2 6 7 .9 6 8 .1 2 P e e r A P e e r D 7 .9 4 P e e r E 7 .9 4 P e e r F 7 .7 3 7 .7 5 P e e r H P e e r G 7 .7 5 Top Quartile(1) P e e r I P e e r E 1 0 0 .0 0 % 1 0 0 .0 0 % P e e r C P e e r A P e e r B 9 9 .9 9 % 1 0 0 .0 0 % P e e r D 9 9 .9 8 % E x e lo n 9 9 .9 6 % 9 9 .9 6 % P e e r F 9 9 .9 0 % P e e r G 9 9 .9 0 % P e e r H 9 9 .8 6 % Top Quartile(1) P e e r I Gas Odor Response(5)Customer Satisfaction(4) Better Better

9 Safely Powering Reliability and Resilience Undergrounding Cable Initiative • DC Power Line Undergrounding is a multi-year program to underground more than 20 of the most vulnerable overhead distribution lines, spanning over 6-8 years with work that began in early 2019 • Expected to improve resiliency against major storms and to improve reliability by an estimated 95% on selected feeders Superconductor Technology • ComEd is the first utility in the U.S. to permanently install superconductor cable technology at a substation in Chicago’s Irving Park neighborhood • Superconductor technology can support 200 times the current of standard copper wire, and allows electricity to be rerouted creating a backup system that keeps electricity flowing in the event of a major power grid interruption Gas Replacement Programs • BGE STRIDE program replaced ~300 miles of gas main and more than 32,000 gas service pipes since 2014, connecting customer properties to gas mains with modern, durable equipment • Since 2015, PECO has replaced 334 miles of gas mains and approximately 27,000 services to ensure the safety and reliability for its customers 0.65 0.72 0.67 0.59 0.57 0.51 Top Quartile(1) 20182017 2019 2020 2021 2022 84 86 87 80 78 77 2020 20222017 20212018 2019 Top Quartile(1) SAIFI 2.5 Beta(2,4) CAIDI 2.5 Beta(3,4) Better Better Grid Modernization Drives Consistent Reliability Performance(1) (1) Quartiles are calculated using reported results by the full panel of peer companies that are deemed most comparable to Exelon’s utilities each year; quartiles reflect data from two years prior to the indicated year, which is the latest data set available for the entirety of that year. (2) Reflects the average number of interruptions per customer reported by Exelon and 20 comparable peer utilities (sources: First Quartile (1QC) T&D, PSE&G Electric Peer Panel Survey, or EIA). (3) Reflects the average time to restore service to customer interruptions reported by Exelon and 20 comparable peer utilities (sources: First Quartile (1QC) T&D, PSE&G Electric Peer Panel Survey, or EIA). (4) Higher frequency and duration of outages in 2018/2019 were due to minor weather events that were not declared as a major event day, and as a result were not excludable from calculations.

10 Advancing Clean Energy Choices and Driving Customer Value Consistently Delivering Top Quartile Customer Satisfaction Scores(2) Energy Efficiency • Offer nationally recognized energy efficiency portfolios, including incentives and behavioral programs across all our jurisdictions, saving almost 24.8M MWh in 2022 Smart Meters(1) • 94.8% and 97.0% of electric and gas customers, respectively, have smart meters that allow greater customer participation in the energy system and enhance power grid operational capabilities Transportation Electrification • Enabling the installation of more than 7,000 residential, commercial, and/or utility-owned charging ports across Maryland, Washington D.C., Delaware, and New Jersey • Rebates and incentives support the development of make-ready infrastructure and/or installation of eligible smart chargers Distributed Energy Resource (DER) Enablement • Enabled more than 200,000 customers to connect 3,089 MW of local renewable generation to the grid through 2022 7.92 2017 7.97 2018 8.10 2019 8.23 2020 8.19 2021 Top Quartile(3) 8.09 2022 Customer Satisfaction Better (1) Exelon utility companies, with the exception of ACE, have completed their planned major smart meter program deployments. ACE began deployment in September 2022 and will complete work in 2024. (2) Reflects the measurements of perceptions of reliability, customer service, price and management reputation by residential and small business customers reported to Escalent by Exelon and 18 comparable peer utilities. (3) Quartiles are calculated using reported results by the full panel of peer companies that are deemed most comparable to Exelon’s utilities each year; quartiles reflect data from two years prior to the indicated year, which is the latest data set available for the entirety of that year.

11 Alternative Regulatory Mechanisms Across Variety of Jurisdictions (1) Reflects expected rate base growth for 2023E-2026E (calculated from 2022 base year); DPL MD transition from traditional base rates to multi-year plan in 2023 more than offsets projected growth in remaining jurisdictions with traditional base rates (i.e., DPL DE and ACE). (2) Figure assumes implementation of multi-year rate plan for ComEd (filed on January 17, 2023). (3) ComEd distribution formula rate expires in 2022, but 2023 effective rates are based on the final formula rate approved in November 2022. 2023-2026E Rate Base Growth of $18B(1) 43% 7% 20% 18% 13% Multi-Year Plan(2) ComEd Distribution Formula(3) Tracker Mechanisms Fully Projected Future Test Year Transmission Formula Exelon projects ~$18B of expected rate base growth over 2023 to 2026 to be 100% recovered through alternative recovery mechanisms 2022 Rate Base Composition 18% 37% 25% 20% ComEd BGEPECO PHI

12 Exelon is an Industry Leader in ESG DIVERSITY, EQUITY & INCLUSION (DE&I) • Executive Committee is 64% women or people of color • Created Executive-led Racial Equity Task Force in 2020 SUPPORTING OUR DIVERSE COMMUNITIES • More than 80 company-sponsored workforce development programs address economic inequities in our communities • $2.9 billion of expenditures with diverse suppliers represented 39% of total utility sourced supplier spend in 2022 • Launched the $36 million Racial Equity Capital Fund and $3 million Exelon HBCU Corporate Scholars Program in 2021 ENERGY AFFORDABILITY • Utility customer bills as a percent of median income is below the national average • Rates in Exelon’s service territories are 23% below the largest U.S. metro cities • Connected our income-eligible customers to ~$590M of financial energy assistance in 2022, which was ~25% higher than 2021 levels NET-ZERO CLIMATE GOAL • No owned generation supply • Targeting a reduction of our operations-driven Scope 1 and Scope 2 emissions by 50% by 2030 and net-zero for these emissions by 2050 through our Path to Clean initiative ADVANCING CLEAN AND AFFORDABLE ENERGY CHOICES • Green Power Connection Program enables interconnection of local renewables • Energy efficiency programs helped customers save almost 24.8 million MWhs in 2022 INVESTING IN CLIMATE SOLUTIONS • Launched the $20 million Climate Change Investment Initiative (2c2i) in 2019, driving investment in emerging technologies that support clean energy transition and resilience STRONG CORPORATE GOVERNANCE ACROSS THE ORGANIZATION • Ranked 70th out of the S&P 250 in Labrador Advisory Services’ 2022 Transparency Awards, which recognizes the quality and completeness of information that top U.S. companies make available to investors • Executive compensation is tied to customer, strategy, financial and operational goals • Stock ownership requirement for executives and directors aligns interests with stakeholders • Ranked in the top 15% of all S&P companies in the 2022 CPA-Zicklin Index for Corporate Political Disclosure and Accountability, earning designation as an index Trendsetter with a 92.9% score ENHANCING EXELON BOARD DE&I • 88% of Board members are independent, including independent Board Chair • 63% diverse Board of which 50% are people of color and 38% are women Environmental Social Governance (1) Reflects Board statistics as of February 17, 2023, exclusive of proposed updates as announced in 8-K on February 14, 2023.

13 Path to Clean: Reaching a Net-Zero Footprint COMPANY AND OPERATIONS Reducing Operations-Driven Emissions by 50% by 2030 and Net-Zero by 2050 to Align with National Decarbonization Goals COMMUNITY SUPPORT Areas for Engagement and Advocacy Electrify 30% of our light and heavy-duty vehicle fleet by 2025 and 50% by 2030 Focus on efficiency, conservation and clean electricity for our operations Invest in equipment and processes to reduce SF6 leakage from our systems Modernize our natural gas infrastructure to minimize methane leaks and increase safety and reliability The Path to Meeting Exelon’s Scope 1 and 2, Operations-Driven Emissions Reduction Goals 790 550 390 800 0 200 600 400 2030 T h o u s a n d M e tr ic T o n s o f C O 2 e 2015 Baseline 2020 Emissions Offsets 2050 Achieve net- zero operations by 2050 Cut operations- driven emissions in half by 2030 EMPOWERING CUSTOMERS Areas for Innovation and Technology Advancement Efficient grid management and grid modernization technologies to minimize system losses Leak detection technologies to reduce natural gas lifecycle emissions and increase safety Partner with communities to develop and implement clean energy solutions that are accessible to all customers Understand jurisdictional differences in energy use needs to develop reliable decarbonization solutions Invest in and support small businesses that are tackling climate problems in our communities Build connected communities that harness digital solutions to integrate clean technologies Driving Scope 3 Customer Emissions Reductions by Supporting Clean Energy Goals in Our Communities Transportation electrification, efficiency, and conservation programs for our customers Leverage alternative fuels to reduce natural gas lifecycle emissions Existing technology and policy supports 80% of targeted reductions Exelon has aligned its corporate goal with the national science-based target, with existing solutions identified for 80% of the reductions, and is proactively investing in pilot technologies and solutions to address remaining 20%

14 Financial Outlook

15 Customer Needs and Industry Trends Continue to Support Investment Growth $22.9B $26.0B $26.7B $29.0B $20.8B $6.7B $3.9B 2019 - 2022E $31.3B 2021 - 2024E2020 - 2023E 2022 - 2025E 2023 - 2026E … and translates to higher rate base(2) growth 4-year capital investment(1) profile drives benefits for our customers... (1) 4-year capital outlook for 2022-2025E reflects capital forecast as presented at Analyst Day 2022; forecast for 2023-2026E as of Q4 2022 earnings call. (2) Reflects current year end rate base projections. Exelon’s $31.3B low-risk capital plan from 2023 to 2026 results in expected rate base growth of 7.9% $51.4B $56.2B $60.8B $65.0B $44.8B $14.2B $10.6B 2022 2023E 2024E 2025E 2026E $69.6B 7.9% Gas Delivery Electric Transmission Electric Distribution Goodings Grove 345kV Transmission $111 million from 2023-2026 Elkins Park Building Substation $45 million from 2023-2026 Erdman to Summerfield Transmission Expansion $301 million from 2023-2026 Downtown 34-69kV Resupply $231 million from 2023-2026 Largest T&D Projects in 2023-2026 Capital Plan

16 Exelon’s Annual Earned Operating ROEs* 9.5% 9.4% 9.6% 10.0% 8.7% 9.2% 9.4% 2022202020182016 20192017 2021 Note: Represents the twelve-month periods December 31, 2016-2022 for Exelon’s utilities (excludes Corp). Earned operating ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Gray-shaded area represents Exelon’s 9-10% targeted range. Delivered 2022 operating ROE* within our 9-10% targeted range

17 Managing Costs Well Below the Rate of Inflation $ in millions ❖ Exelon is well positioned to manage inflationary pressures • Working with business partners to mitigate price increases and avoid long lead times through negotiations, utilizing alternative suppliers, and purchasing in bulk • World-class Supply organization leveraging economies of scale • 44% of labor force is represented, with contract renewals over 2023 to 2027 ❖ Since 2016, adjusted O&M* is projected to increase at an annualized rate of 1.7% through 2023, which is well below the rate of inflation, benefitting customer bills by avoiding $500M+ of inflationary impacts(4) ❖ Beyond Exelon’s proven cost management discipline, other elements contribute to efforts to keep total customer bills affordable • Carbon Mitigation Credit (CMC) contracts in Illinois • Financial assistance programs for income-eligible customers • Energy efficiency programs ❖ Exelon’s customers’ electricity bills as a % of median income are ~30% below the U.S. average of 2.1%(5) Addressing Customer Affordability Across Multiple Dimensions (1) Reflects adjusted O&M* for Exelon’s utilities which includes allocated costs from the shared services company; numbers rounded to the nearest $25M. (2) 2022 actual adjusted O&M includes $34M of CEJA-related costs at ComEd that were treated as regulatory asset spend in 2022 but reclassified to adjusted operating O&M beginning in 2023. (3) Source: Edison Electric Institute Typical Bills and Average Rates report for Summer 2022; reflects residential average rates for the 12-month period ending 6/30/2022. Los Angeles and Boston residential average rate data for the 12-month period ending 6/30/2022 sourced from Energy Information Administration (EIA-861M). High-population cities that do not provide data (e.g., Houston) are excluded from analysis. Chart reflects a sample of the top 20 cities for illustrative purposes. (4) Assuming an average annual 3.2% rate of inflation based on consumer price index as reported by the Bureau of Labor Statistics and IHS across 2016-2023, adjusted O&M costs would have increased by ~$1B over the same time period. (5) Sources: 2021 EIA Residential Electric Revenue and Customer data by provider for Full-Service Providers, and median income for U.S. using US Census Bureau 2021 ACS 1-Year Estimates. $3,725 $3,725 $3,900 $3,800 $3,950 $3,950 $4,150 $4,200 202020182016 20222017 2019 2021 2023E 1.7% Rates 23% Below Largest U.S. Metro Cities 1 8 .0 7 1 4 .4 1 1 4 .2 0 1 4 .1 2 1 3 .6 3 1 3 .1 9 1 2 .7 8 1 2 .4 4 1 2 .1 9 1 1 .1 0 2 8 .4 2 3 1 .6 6 N e w Y o rk S a n D ie g o 2 6 .5 0 L o s A n g e le s B o s to n 2 1 .9 4 2 1 .6 8 S a n F ra n c is c o D e tr o it M in n e a p o lis C h ic a g o A tl a n ta P h o e n ix B a lt im o re Top 20 City Average: 17.04 W a s h in g to n , D .C . P h ila d e lp h ia U.S. Average: 14.39 M ia m i S t. L o u is Exelon Service Territory cents/kWh(3) Adjusted O&M ($M)*(1)(2) Focused on Managing Costs to Support Affordability

Long-Term Earnings Growth Supports Sustainable Dividend 18 Targeting 6-8% Operating Earnings* CAGR from 2022 - 2026(1)(5) Note: amounts may not sum due to rounding (1) Includes after-tax interest expense associated with debt held at Corporate. (2) Reflects 2022 original earnings guidance based on expected average outstanding shares of 983M. ComEd’s 2022E original earnings guidance was based on a forward 30-year Treasury yield as of 12/31/2021. (3) 2023E earnings guidance based on expected average outstanding shares of 996M. ComEd’s 2023E earnings guidance is based on a forward 30-year Treasury yield as of 1/31/2023. (4) Dividend is subject to approval by the Board of Directors. (5) Based off the midpoint of Exelon’s 2022 Adjusted EPS* guidance range of $2.18 - $2.32 as disclosed at Analyst Day in January 2022. (6) Based off the midpoint of Exelon’s 2021 Adjusted EPS* guidance range of $2.06 - $2.14 as disclosed at Analyst Day in January 2022. Exelon is targeting operating EPS* CAGR of 6-8% from 2022 to 2026, and projecting a ~60% dividend payout ratio of operating earnings* that will grow in-line with the targeted 6-8% EPS* growth $2.30 - $2.42(3) 2022E 2023E $2.18 – $2.32(2) • Reaffirm prior target of 6-8% operating EPS* CAGR from 2021-2025(6), with expectation to be at midpoint or better • Current target of 6-8% operating EPS* CAGR from 2022-2026(5), with expectation to be at midpoint or better • Annual growth in 2024 and beyond projected to be within the 6-8% range, if not above it; slide 23 provides year-over- year growth drivers Expect ~60% dividend payout ratio resulting in dividend growing in-line with targeted 6-8% operating EPS* CAGR through 2026 Projected Dividend Payout(4) 6-8% $1.35 $1.44 2022A 2023E 6-8%

19 Maintaining a Strong Balance Sheet is a Top Financial Priority S&P FFO / Debt %* and Moody’s CFO (Pre-WC) / Debt %* Credit Ratings(4) ExCorp ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 A1 Aa3 A3 A2 A2 A2 S&P BBB A A A A A A Fitch BBB A A+ A A A A 14% 0% 12% 13% 15% 2023-2026E Average(1,2) 12% Exelon Downgrade Threshold(3) 13-14% Strong balance sheet and low-risk attributes provide strategic and financial flexibility (1) 2023–2026 average internal estimate based on S&P and Moody’s methodology, respectively. (2) Without tax repairs deduction, CAMT cash impact expected to result in 2023–2026 average at the low end of range; with tax repairs deduction, CAMT cash impact expected to result in 2023–2026 average at the high end of range. (3) S&P and Moody’s downgrade thresholds based on their published reports for Exelon Corp. (4) Current senior unsecured ratings for Exelon and BGE and current senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco. • Pure-play T&D utility company operating across 7 different regulatory jurisdictions • Largest T&D utility in the country, serving 10+ million customers • Track record of top quartile reliability performance • Geographically diverse group of utilities in supportive regulatory jurisdictions • ~100% of rate base growth covered by alternative recovery mechanisms and ~73% decoupled from volumetric risk Low-risk Attributes Support a Strong Credit Profile

20 Appendix

21 2023 Business Priorities and Commitments Focused on continued execution of operational, regulatory, and financial priorities to build on the strength of Exelon’s value proposition as the premier T&D utility ❖Maintain industry-leading operational excellence ❖ Achieve constructive rate case outcomes for customers and shareholders ❖ Deploy $7.2B of capex for the benefit of the customer ❖ Earn consolidated operating ROE* of 9-10% ❖ Deliver against operating EPS* guidance of $2.30 - $2.42 per share ❖Maintain strong balance sheet and execute on 2023 financing plan Industry-Leading Platform Leading ESG Profile Operational Excellence Financial Discipline Sustainable Value ❖ Continue to advocate for equitable and balanced energy transition ❖ Focus on customer affordability, including through cost management

22 2023 Adjusted Operating Earnings* Guidance Key Year-over-Year DriversAdjusted Operating Earnings* Guidance(1) Incremental investments in utility infrastructure Discontinued operations adjustment not applicable in post-separation results BGE and PHI MYP 1 reconciliation in process Return to normal storm activity and weather Incremental debt at Corporate and other financing costs 2022 Original Guidance 2023 Original Guidance $2.18 - $2.32(2) $2.30 - $2.42(3) (1) Includes after-tax interest expense associated with debt held at Corporate (2) 2022 earnings guidance based on expected average outstanding shares of 983M. ComEd’s 2022E earnings guidance was based on a forward 30-year Treasury yield as of 12/31/2021. (3) 2023 earnings guidance based on expected average outstanding shares of 996M. ComEd’s 2023E earnings guidance is based on a forward 30-year Treasury yield as of 1/31/2023. 2023 operating EPS* growth of ~5% from 2022 guidance midpoint to 2023 guidance midpoint

23 Key Modeling Drivers and Assumptions 2023 2024 2025 2026 OpCo Drivers(1) YoY EPS Drivers(1) YoY EPS Drivers(1) YoY EPS Drivers(1) YoY EPS BGE Gas and electric MYP 1 year 3 rates, MYP 1 reconciliation (2021 and 2022), and transmission, offset by MYP 1 regulatory lag Gas and electric MYP 2 year 1 rates, MYP 1 reconciliation (2023), and transmission Gas and electric MYP 2 year 2 rates and transmission Gas and electric MYP 2 year 3 rates and transmission ComEd Distribution and transmission rate base growth; 30-Yr TSY on ROE Distribution and transmission rate base growth (MYP 1 year 1 rates) Distribution and transmission rate base growth (MYP 1 year 2 rates) Distribution and transmission rate base growth (MYP 1 year 3 rates) PECO Return to normal weather and storm, electric year 2 in 3-yr cadence of FPFTY, partially offset by year 1 gas rates, transmission, and electric DSIC tracker(2) Electric year 3 and gas year 2 in 3- yr cadence of FPFTY, offset by transmission and DSIC tracker(2) Year 1 electric rates, transmission, and gas DSIC tracker, partially offset by gas year 3 in 3-yr cadence of FPFTY(2) Electric year 2 in 3-yr cadence of FPFTY, partially offset by year 1 gas rates, transmission, and electric DSIC tracker(2) PHI Pepco MD MYP 1 year 3, DPL MD MYP 1 year 1, DPL DE gas and electric rates, and transmission, partially offset by Pepco DC MYP 1 stay out regulatory lag Pepco DC and MD MYP 2 year 1, DPL MD MYP 1 year 2 rates, and transmission Pepco DC and MD MYP 2 year 2, DPL MD MYP 1 year 3 rates, and transmission Pepco DC and MD MYP 2 year 3, DPL MD MYP 2 year 1 rates, and transmission Corp $1.65B of new debt and other financing costs, partially offset by the absence of disc. ops adj. Portion of $3.4B of 2024-2026 new debt and other financing costs Portion of $3.4B of 2024-2026 new debt and other financing costs Portion of $3.4B of 2024-2026 new debt and other financing costs Total YoY Growth Relative to Range Growth Below Low End of 6-8% Range Growth in Low End of 6-8% Range Growth Above 6-8% Range Growth in Middle of 6-8% Range Note: YoY earnings growth estimates are for illustrative purposes only to provide indicative YoY variability; arrows indicate incremental contribution or drag to YoY operating EPS* growth but not necessarily equivalent in terms of relative impact (1) Reflects publicly known distribution rate cases that Exelon has filed or expects to file in 2023. Excludes traditional base rate cases with filing dates that are not yet available to the public. Known and measurable drivers as of 4Q22 earnings call. (2) PECO assumes a 3-year rate case cadence of Fully Projected Future Test Year (FPFTY) for long-range planning purposes; i.e., filing in 2024 and 2025 for electric and gas distribution, respectively. (3) 2021-2025 and 2022-2026 EPS CAGRs based off the midpoints of Exelon’s 2021 Adjusted EPS* guidance range of $2.06 - $2.14 and Exelon’s 2022 Adjusted EPS* guidance range of $2.18 - $2.32 as disclosed at 2022 Analyst Day, respectively. Rate case activity and investment plan drives annual growth path towards expectation of being at midpoint or better of expected 6-8% operating EPS* CAGRs(3) for 2021 - 2025 and 2022 - 2026

24 Utility Capex and Rate Base vs. Previous Disclosures Q4 2022 Capital Expenditures ($M) Q4 2022 Rate Base ($B) Analyst Day 2022 Capital Expenditures ($M) Analyst Day 2022 Rate Base ($B) 4,525 4,650 4,875 4,850 1,500 1,525 1,600 1,725 875 900 975 950 7,100 2023E 7,500 2022E 2024E 2025E 6,900 7,450 4,775 4,825 4,975 5,400 5,575 1,450 1,450 1,600 1,825 1,800900 925 975 975 1,000 2024E2023E 2026E2022 7,150 2025E 7,175 7,550 8,200 8,350 31.4 33.9 36.3 39.0 41.3 9.9 10.9 11.6 12.9 14.4 9.3 7.8 6.2 2021E 2024E 60.5 7.2 2022E 2023E 8.6 2025E 52.047.6 55.7 65.0 +8.1% 33.7 36.5 39.3 41.8 44.8 10.5 11.7 12.6 13.4 14.2 8.9 9.8 10.6 7.1 2022 2025E 60.8 2023E 8.0 2024E 2026E 51.4 56.2 65.0 69.6 +7.9% Gas Delivery/Other(1) Electric Transmission Electric Distribution(2) Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Other includes long-term regulatory assets, which generally earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program. (2) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Planning to invest $31.3B of capital from 2023-2026 for the benefit of our customers, supporting projected rate base growth of 7.9% from 2022-2026

25 ComEd Capital Expenditure Forecast Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Project ~$11.1B of capital being invested from 2023-2026 2,100 2,075 2,025 2,350 2,450 425 475 525 575 650 2026E2022 2023E 2,525 2025E 2,550 2024E 2,550 2,925 3,100 2,025 2,050 2,000 1,975 450 500 575 675 2022E 2025E2023E 2,650 2024E 2,575 2,475 2,550 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Other includes long-term regulatory assets, which generally earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program. (2) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Rate Base 2022: 37% of Total Exelon Rate Base 6% 22% 72% Gas Delivery/Other(1) Electric Transmission Electric Distribution(2) $19.1B

Project ~$6.2B of capital being invested from 2023-2026 26 PECO Capital Expenditure Forecast 875 975 1,150 1,200 1,225 175 75 75 350 325 375 375 350 1,650 2025E2022 1,375 2024E2023E 50 1,575 50 2026E 1,400 1,600 850 950 1,075 1,100 175 75 100 125325 325 375 375 1,550 1,325 2022E 2024E2023E 2025E 1,375 1,575 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 20% of Total Exelon Rate Base 26% 11%63% Gas Delivery/Other Electric Transmission Electric Distribution(1) $10.2B

Project ~$6.0B of capital being invested from 2023-2026 27 BGE Capital Expenditure Forecast 625 525 525 525 525 225 325 425 625 450 475 475 525 525 550 1,475 2026E2022 2023E 1,675 1,325 2024E 1,325 2025E 1,550 500 450 475 500 275 400 400 400 475 475 500 500 2023E2022E 2024E 1,325 1,225 2025E 1,4001,375 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 18% of Total Exelon Rate Base 31% 19% 49% Gas Delivery/Other Electric Transmission Electric Distribution(1) $9.1B

28 PHI Consolidated Capital Expenditure Forecast 1,200 1,225 1,275 1,325 1,375 650 550 575 600 625 125 100 2026E 1,925 2023E 75 2025E2022 2024E 75 75 1,900 1,950 1,975 2,075 1,175 1,200 1,325 1,275 600 525 550 550 100 100 2025E 75 2022E 2023E 2024E 75 1,850 1,825 1,950 1,875 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Project ~$7.9B of capital being invested from 2023-2026 Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 25% of Total Exelon Rate Base 4% 26% 69% Gas Delivery/Other Electric Transmission Electric Distribution(1) $13.0B

Project ~$1.8B of capital being invested from 2023-2026 29 ACE Capital Expenditure Forecast 275 300 250 275 275 175 150 200 200 200 2022 2026E 425 2023E 2024E 2025E 450 450 475 475 300 300 300 275 175 150 175 175 2024E2022E 475 2023E 2025E 475 450 450 Electric Distribution(1)Electric Transmission Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 6% of Total Exelon Rate Base 39% 61% $3.2B

Project ~$2.4B of capital being invested from 2023-2026 30 DPL Capital Expenditure Forecast 250 275 325 300 350 150 175 175 225 20075 125 100 75 75575 2023E 600 2022 2024E 2025E 475 2026E 575 600 250 250 300 275 150 150 150 175 100 100 75 75 525 475 2022E 2023E 525 2024E 500 2025E Electric TransmissionGas Delivery Electric Distribution(1) Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 7% of Total Exelon Rate Base 15% 31% 54% $3.6B

31 Pepco Capital Expenditure Forecast 675 650 725 750 775 325 250 225 175 225 900 2022 2026E2023E 2024E 925 2025E 1,000 900 975 625 650 725 700 275 225 225 200 2023E 900 900 2022E 900 2024E 2025E 950 Electric Transmission Electric Distribution(1) Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. Analyst Day 2022 capex disclosures dated January 10, 2022. Q4 2022 disclosures dated February 14, 2023. (1) Electric distribution rate base includes regulatory assets that earn a full authorized Rate of Return; regulatory asset spend not reflected in capital spend projections. Project ~$3.7B of capital being invested from 2023-2026 Q4 2022 Capital Expenditures ($M)Analyst Day 2022 Capital Expenditures ($M) Rate Base 2022: 12% of Total Exelon Rate Base 17% 83% $6.1B

2023 Financing Plan(1) Capital plan financed with a balanced approach to maintain strong investment grade ratings OpCo Instrument Issuance ($M) Maturity ($M) Issued ($M)(3) Remaining ($M) FMB $975 - $975 - FMB $350 - $350 - FMB $75 - $75 - FMB $650 ($500) $650 - FMB $525 ($50) - $525 Senior Notes $700 ($300) $700 - Senior Notes $2,500 ($850)(2) $2,500 - Equity $425M of equity expected between 2023 and 2025 - - - Note: 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) Represents $850M of term loans repaid on March 14, 2023. (3) Issued amounts as of March 31, 2023. Pepco, ACE, and DPL priced FMBs in the private placement market in February 2023. As of March 15, 2023, Pepco, ACE, and DPL funded $250M, $75M, and $125M, respectively. Using a delayed draw feature, Pepco and DPL will fund $100M and $525M in September and November 2023, respectively. 32

33 2023-2026 Financing Plan ~$17 ~$31 ~($6) ~$6 ~$13 Utility Investment 2023-2026 Adjusted Cash from Operations*(1) 2023-2026 Debt Maturity Debt Refinance Debt Issuance(2) ~$0.4 Equity Issuance(3) $ in billions Note: Financing plan is subject to change (1) Adjusted Cash from Operations* is net of common dividends and change in cash on hand. (2) Includes both utility and corporate debt. Anticipate maintaining ~51% equity to capital ratio at the utilities. Of the $13B, corporate debt issuances expected to be approximately $5 billion over 2023-2026. (3) Expect to issue the remaining $425 million of equity between 2023 and 2025. Balanced investment and value return strategy results in limited equity needs over the next several years

34 Exelon Distribution Rate Case Updates Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Revenue Requirement Requested ROE / Equity Ratio Expected/Received Order Date $41.8M (1,2) 10.50% / 50.50% Q2 2024 $1.49B (1,4) 4-Year MYP 2024: 10.50% / 50.58% 2025: 10.55% / 50.81% 2026: 10.60% / 51.03% 2027: 10.65% / 51.19% Dec 2023 $93.6M(1,5) 10.50% / 50.20% Q1 2024 $602.3M (1,7) 3-Year MYP 10.40% / 52.00% Dec 2023 $190.7M (1,8) 3-Year MYP 10.50%/ 50.50% Feb 2024 $213.6M (1,9) 3-Year MYP 10.50%/ 50.50% Mar 2024 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 DPL DE Electric ComEd(3) ACE Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission (ICC), Maryland Public Service Commission (MDPSC), Pennsylvania Public Utility Commission (PAPUC), Delaware Public Service Commission (DPSC), Public Service Commission of the District of Columbia (DCPSC), and New Jersey Board of Public Utilities (NJBPU) 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 $13.7M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power may implement full proposed rates on July 15, 2023, subject to refund. (3) On April 21, 2023, ComEd filed its 2022 formula rate reconciliation seeking recovery of $247M for rates effective on January 1, 2024, with an order expected by December 17, 2023. (4) Reflects 4-year cumulative multi-year rate plan. ComEd proposes a phase in plan that accrues revenues but defers recovery of 35% of the 2024 increase of $904M until 2026. (5) As permitted by New Jersey law, Atlantic City Electric may implement full proposed rates on November 17, 2023, subject to refund. Procedural schedule for ACE base rate case is expected to be finalized in Q2 2023. (6) In its Annual Informational Filings filed with the MDPSC on March 31, 2022 and March 31, 2023, BGE is requesting to recover an imbalance of $17.8M for 2021 and $58.7M for 2022. An order is expected to coincide with MYP by December 14, 2023. (7) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases with rates effective January 1, 2024, January 1, 2025, and January 1, 2026, respectively. The proposed revenue requirement increase in 2024 reflects $84.8M increase for electric and $158.3M increase for gas; 2025 reflects $103.3M increase for electric and $77.0M increase for gas; 2026 reflects $125.0M increase for electric and $54.0M increase for gas. These include a proposed acceleration of certain tax benefits in 2024 and 2025 for electric, and 2024 for gas. (8) Expected order date based on the Company’s proposed 10-month procedural schedule. Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $116.4M, $36.9M, and $37.3M with rates effective February 15, 2024, January 1, 2025, and January 1, 2026, respectively. The cumulative revenue requirement does not total to $190.7 million due to rounding. (9) Reflects 3-year cumulative multi-year plan with a proposed 9-month extension. Company proposed incremental revenue requirement increases with rates effective April 1, 2024, April 1, 2025, April 1, 2026, and April 1, 2027. Pepco is proposing to extend this MYP through December 31, 2027 in order to position utilities currently operating under MYPs to file future applications on staggered schedules and avoid over-burdening Commission Staff and other parties. An order is expected by March 11, 2024 per statute. CF CF IT RT EH IB RB BGE(6) CF CF IT RT EH IB RB FO FO Pepco DC CF IT RT EH Pepco MD CF IT RT EH

35 Delmarva DE (Electric) Distribution Rate Case Filing (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 $13.7M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power may implement full proposed rates on July 15, 2023, subject to refund. Rate Case Filing Details Notes Docket No. 22-0897 • December 15, 2022, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution rates • This rate increase will support significant investments in infrastructure to maintain safety, reliability and customer service for our customers, as well as address emerging macroeconomic factors, specifically inflationary pressures and increased storm costs • May 30, 2023 DPL DE filed 9+3 supplemental direct testimony based on nine months actual and three months forecasted data ending June 30, 2023; update to test period resulted in revised revenue requirement request of $41.8M Test Period July 1 – June 30 Test Year 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.50% Proposed Rate of Return ROE: 10.50%; ROR: 7.44% Proposed Rate Base (Adjusted) $1,083M Requested Revenue Requirement Increase $41.8M(1,2) Residential Total Bill % Increase 5.32% Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr 12/15/2022 Rebuttal testimony Filed rate case Evidentiary hearings Initial briefs Intervenor testimony Reply briefs Q2 2024Commission order expected 9/29/2023 12/4/2023 - 12/7/2023 8/18/2023

36 ComEd Distribution Rate Case Filing (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) Reflects the revenue requirement increases without the effects of ComEd’s proposed phase-in approach. ComEd proposes a phase-in plan that defers recovery of 35% of the 2024 increase of $904M until 2026. (3) Includes the effects of the proposed phase-in approach. (4) Commission order expected no later than 12/20/2023. Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 9/12/2023 Intervenor testimony Initial briefs 5/22/2023 Filed rate case 1/17/2023 Reply briefs 12/20/2023(4) Rebuttal testimony 9/27/2023 6/27/2023 8/21/2023Evidentiary hearings Commission order expected Multi-Year Plan Case Filing Details Notes Formal Case No. 23-0055 • January 17, 2023, ComEd filed a four-year multi-year plan (MYP) request with the Illinois Commerce Commission (ICC) seeking an increase in electric distribution base rates • Proposal aligns with the investments in ComEd MYIGP, which was also filed with the ICC on January 17, 2023. The two cases were consolidated into a single proceeding on January 23, 2023 • The proposal includes a phase-in of new rates, deferring 35% of the first year’s bill impact until 2026, as allowed under the Climate & Equitable Jobs Act (CEJA) • April 19, 2023, ComEd updated the filing to include approximately $30M/year of beneficial electrification costs from 2024 to 2027 • Separately, on April 21, 2023, ComEd filed its 2022 formula rate reconciliation seeking recovery of $247M for rates effective on January 1, 2024. An order is expected by December 17, 2023 Test Period January 1 – December 31 Test Year 2024, 2025, 2026, 2027 Proposed Common Equity Ratio 50.58% in 2024 increasing to 51.19% in 2027 2024-2027 Proposed Rate of Return ROE: 10.50%, 10.55%, 10.60%, 10.65% ROR: 7.43%, 7.50%, 7.62%, 7.70% 2024-2027 Proposed Rate Base (Adjusted) $15.5B; $16.5B; $17.6B; $18.8B 2024-2027 Requested Revenue Requirement Increase $904M, $173M, $216M, $203M(1,2) 2024-2027 Residential Total Bill % Increase 7.3%, 5.8%, 6.0%, (1.4%)(3) Detailed Rate Case Schedule

37 ACE Distribution Rate Case Filing (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) As permitted by New Jersey law, Atlantic City Electric may implement full proposed rates on November 17, 2023, subject to refund. Detailed Rate Case Schedule Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan 2/15/2023Filed rate case Rebuttal testimony 11/9/2023 - 12/13/2023Evidentiary hearings Initial briefs 9/1/2023 Reply briefs Q1 2024Commission order expected 10/6/2023 Intervenor testimony Rate Case Filing Details Notes Docket No. ER23020091 • February 15, 2023, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (NJBPU) to increase distribution base rates • This rate increase will support significant investments in infrastructure to maintain safety, reliability and customer service for customers • Includes initial recovery for ACE’s smart meter deployment (“Smart Energy Network”) and EVsmart program • Addresses macroeconomic factors, specifically inflationary pressures and increased storm costs, and includes a Prudency Review for the PowerAhead program, which made storm-hardening investments from 2017-2022 • June 1, 2023, ACE filed 9+3 supplemental direct testimony based on nine months actual and three months forecasted data ending June 30, 2023; update to test period resulted in revised revenue requirement request of $93.6M Test Period July 1 – June 30 Test Year 9 months actual + 3 months forecast Proposed Common Equity Ratio 50.20% Proposed Rate of Return ROE: 10.50%; ROR: 7.13% Proposed Rate Base (Adjusted) $2,219M Requested Revenue Requirement Increase $93.6M(1,2) Residential Total Bill % Increase 8.27%

38 BGE Distribution Rate Case Filing Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Rebuttal testimony 6/20/2023 2/17/2023Filed rate case Evidentiary hearings Intervenor testimony Initial briefs Reply briefs Commission order expected 7/31/2023 10/20/2023 10/10/2023 12/14/2023(4) 8/30/2023 – 9/8/2023 Multi-Year Plan Case Filing Details Notes Formal Case No. 9692 • February 17, 2023, BGE filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric and gas distribution base rates. • The proceeding will also reconcile the first two years of BGE’s first MYP. BGE is requesting to recover an imbalance(3) of $17.8M and $58.7M for 2021 and 2022, respectively • The increase is driven by investments to continue providing safe and reliable electric and gas distribution service to customers while laying the foundation for BGE to support the achievement of Maryland’s climate goals Test Period January 1 – December 31 Test Year 2024, 2025, 2026 Proposed Common Equity Ratio 52.00% 2024-2026 Proposed Rate of Return ROE: 10.4% ROR: 7.39%, 7.45%, 7.56% 2024-2026 Proposed Rate Base (Adjusted) $8.1B, $8.8B, $9.5B 2024-2026 Requested Revenue Requirement Increase (1,2) $243.1M, $180.3M, $179.0M 2024-2026 Residential Total Bill % Increase (2) 6.8%, 4.5%, 3.7% Detailed Rate Case Schedule (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) Reflects an average residential customer receiving both electric and gas service from BGE. Company proposed incremental revenue requirement increases with rates effective January 1, 2024, January 1, 2025, and January 1, 2026, respectively. The proposed revenue requirement increase in 2024 reflects $84.8M increase for electric and $158.3M increase for gas; 2025 reflects $103.3M increase for electric and $77.0M increase for gas; 2026 reflects $125.0M increase for electric and $54.0M increase for gas. These include a proposed acceleration of certain tax benefits in 2024 and 2025 for electric, and 2024 for gas. (3) Reflects the imbalanced amounts included in the 2021 and 2022 Annual Informational Filings filed with the MDPSC on March 31, 2022 and March 31, 2023, respectively. The reconciliation of 2021 and 2022 costs are not included in the requested revenue requirement increase. BGE is proposing that these amounts be recovered through separate electric and gas riders in 2024. (4) Expected Order Date per Statute.

39 Pepco DC Distribution Rate Case Filing Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Evidentiary hearings Initial briefs Reply briefs Commission order expected Filed rate case 4/13/2023 Rebuttal testimony Feb 2024(3) Intervenor testimony Multi-Year Plan Case Filing Details Notes Formal Case No. 1176 • April 13, 2023, Pepco submitted its “Climate Ready Pathway DC” three-year multi-year plan (MYP) application to the Public Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • This proposal outlines investments the company will make from 2024-2026 to support a climate ready grid and help support the District’s clean energy goals • The MYP includes a proposal expanding enrollment for the RAD program, operated by the District Department of Energy and Environment, to include more Pepco DC customers who qualify for any low-income program in the District Test Period January 1 – December 31 Test Year 2024, 2025, 2026 Proposed Common Equity Ratio 50.50% 2024-2026 Proposed Rate of Return ROE: 10.5% ROR: 7.77%, 7.78%, 7.79% 2024-2026 Proposed Rate Base (Adjusted) $3.0B, $3.2B, $3.4B 2024-2026 Requested Revenue Requirement Increase (1,2) $116.4M, $36.9M, $37.3M 2024-2026 Residential Total Bill % Increase (2) 6.4%, 6.0%, 5.6% Detailed Rate Case Schedule(3) (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. (2) Company proposed incremental revenue requirement increases with rates effective February 15, 2024, January 1, 2025, and January 1, 2026. The cumulative revenue requirement does not total to $190.7 million due to rounding. (3) Based on Company’s proposed 10-month procedural schedule.

40 Pepco MD Distribution Rate Case Filing May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Initial briefs 5/16/2023Filed rate case Intervenor testimony Rebuttal testimony Evidentiary hearings Reply briefs Commission order expected 3/11/2024(4) Multi-Year Plan Case Filing Details Notes Formal Case No. 9702 • May 16, 2023, Pepco submitted its “Climate Ready Pathway MD” three-year multi-year plan (MYP) application with proposed 9-month extension to the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • This proposal outlines investments the company will make from 2024-2027 to advance the state’s climate and clean energy goals while taking steps to mitigate the impact of these efforts on customer bills • The MYP includes investments in innovative technologies, communications and information technology, reliability and customer-driven projects, and necessary system capacity enhancements needed to support customers through the current energy transformation Test Period April 1 – March 31 Test Year (1) 2024, 2025, 2026, 2027 Proposed Common Equity Ratio 50.50% 2024-2026 Proposed Rate of Return ROE: 10.50% ROR: 7.77%, 7.79%, 7.80%, 7.81% 2024-2026 Proposed Rate Base (Adjusted) $2.6B, $2.8B, $2.9B, $3.0B 2024-2026 Requested Revenue Requirement Increase (2,3) $74.4M, $59.4M, $59.4M, $20.4M 2024-2026 Residential Total Bill % Increase (3) 5.0%, 3.8%, 3.7%, 1.2% Detailed Rate Case Schedule (1) Pepco is proposing to extend this MYP through December 31, 2027 in order to position utilities currently operating under MYPs to file future applications on staggered schedules and avoid over-burdening Commission Staff and other parties. (2) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings. Additionally, Pepco is proposing acceleration of additional tax benefits to offset Rate Year 1 and Rate Year 2 bill impacts. Revenue requirement includes the impact of these proposed offsets. (3) Company proposed incremental revenue requirement increases for 3-year multi-year plan with proposed 9-month extension for rates effective April 1, 2024, April 1, 2025, April 1, 2026, and April 1, 2027. (4) Expected Order Date per Statute.

41 Utility Highlights 2022 Electric Customer Mix (% of Volumes) (1) Commercial & Industrial (C&I) 66% 59% 55% 63% 55% 52% Residential 33% 39% 44% 34% 45% 48% Public Authorities/Other 1% 2% 1% 3% 0% 1% 2022 Gas Customer Mix (% of Volumes) (1) Commercial & Industrial (C&I) - 26% 52% - 28% - Residential - 46% 41% - 41% - Public Authorities/Other - 28% 7% - 31% - Current Rate Recovery Mechanisms Traditional Base Rate Application - - - - X - DE Only X Distribution Formula Rate X (2) - - - - - Multi-Year Plan - - X X X – MD Only - Fully Projected Future Test Year - X - - - - Transmission Formula Rate X X X X X X Tracker Mechanisms for Specified Investments/Programs X X X X X X Decoupling (3) X - X X X - MD Only X Bad Debt Tracker X - - - - X Major Storm Deferral X(4) - X X(5) X - MD Only X Note: “-” cells are indicative of categories that are not applicable to the respective utility (1) Percent of volumes by customer class may not sum due to rounding. (2) ComEd distribution formula rate expired in 2022, but 2023 rates are based on the final formula rate approved in November 2022. 2024 rates will be based on the multi-year rate plan order expected in December 2023. (3) ComEd’s formula rate includes a mechanism that eliminates volumetric risk. Rider DSPR – Delivery Service Pricing Reconciliation will provide decoupling for calendar years 2022 and 2023 after the formula rate expires, while Rider RBA – Revenue Balancing Adjustment, which was approved by the Illinois Commerce Commission in December 2022, will provide decoupling for 2024 and beyond. ACE implemented the Conservation Incentive Program prospectively effective July 1, 2021, which eliminates the variable effects of weather and customer usage patterns for most customers. Certain classes for BGE, DPL MD, Pepco and ACE are not decoupled. (4) Under EIMA statute (220 ILCS 5/16-108.5) and CEJA (220 ILCS 5/16-105.6), ComEd is able to record expenses greater than $10 million resulting from a single storm or weather system or other similar expense to a regulatory asset and amortize over 5 years. (5) In the Pepco DC MYP case, the Company received approval on June 8, 2021 for the ability to request deferral of unexpected costs greater than $1M which could enable regulatory asset treatment for storm recovery.

42 Approved Distribution Rate Case Financials Approved Electric Distribution Rate Case Financials Revenue Requirement Increase/(Decrease) Allowed ROE Common Equity Ratio Rate Effective Date ComEd (Electric) $198.9M 7.85% 49.45% Jan 1, 2023 PECO (Electric) (1) $132.0M N/A N/A Jan 1, 2022 BGE (Electric) (2) $139.9M 9.50% 52.00% Jan 1, 2021 Pepco MD (Electric) (3) $52.2M 9.55% 50.50% Jun 28, 2021 Pepco D.C. (Electric) (4) $108.6M 9.275% 50.68% Jul 1, 2021 DPL MD (Electric) (5) $28.9M 9.60% 50.50% Jan 1, 2023 DPL DE (Electric) $13.5M 9.60% 50.37% Oct 6, 2020 ACE (Electric) $41.0M 9.60% 50.21% Jan 1, 2022 (1) The PaPUC issued an order on November 18, 2021 approving the Joint Petition for Settlement with rates effective on January 1, 2022. The settlement does not stipulate any ROE, Equity Ratio or Rate Base. (2) Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. The MDPSC utilized the tax benefits to fully offset the increases in 2021 and January 2022 such that customer rates remained unchanged. For the remainder of 2022, the MDPSC chose to offset only 25% of the cumulative 2021 and 2022 electric revenue requirement increases and 50% of the cumulative gas revenue requirement increases. After deferring a decision on 2023 and asking BGE to make a new proposal, the MDPSC accepted BGE’s recommendation in October 2022 to not use certain tax benefits to offset 2023 revenue requirement increases. (3) Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12- month periods ending March 31, 2022, 2023, and 2024, respectively. The MDPSC offset customer rate increases through March 31, 2022 with certain accelerated tax benefits, but deferred the decision to use additional tax benefits to offset customer rate increases for the periods after March 31, 2022. (4) Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively. (5) 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. Approved Gas Distribution Rate Case Financials Revenue Requirement Increase/(Decrease) Allowed ROE Common Equity Ratio Rate Effective Date PECO (Gas) $54.8M N/A N/A Jan 1, 2023 BGE (Gas) (2) $73.9M 9.65% 52.00% Jan 1, 2021 DPL DE (Gas) $7.6M 9.60% 49.94% Nov 1, 2022

43 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 $83M 11.50% 55.00% Jun 1, 2023 PECO $30M 10.35% 54.12% Jun 1, 2023 BGE $7M 10.50% 53.48% Jun 1, 2023 Pepco $32M 10.50% 50.50% Jun 1, 2023 DPL $29M 10.50% 50.31% Jun 1, 2023 ACE $29M 10.50% 50.02% Jun 1, 2023 (1) The rate of return on common equity for each Utility Registrant includes a 50-basis-point incentive adder for being a member of a RTO. (2) All rates are effective June 1, 2023 - May 31, 2024, subject to review by interested parties pursuant to protocols of each tariff.

44 Tracker Recovery Mechanisms for Specified Investments / Programs • Distribution System Improvement Charge (DSIC) tracker provides a mechanism to begin recovering gas and electric infrastructure investments for reliability every six months • Strategic Infrastructure Development and Enhancement (STRIDE) program allows for contemporaneous recovery of the accelerated replacement of aging gas infrastructure (cast iron and bare steel mains and copper, bare steel and pre-1970 ¾” high pressure steel services) • EmPOWER MD allows for recovery on energy efficiency and demand response programs • Distribution System Improvement Charge (DSIC) mechanism provides recovery for Long-Term Infrastructure Improvement Plan (LTIIP) for electric and gas distribution in between rate cases • Future Energy Jobs Act (FEJA) permits recovery of energy efficiency programs and distributed generation rebates through formula rates • District of Columbia Power Line Undergrounding (DC PLUG) provides for contemporaneous recovery of reliability and resiliency investments to underground the most vulnerable feeders • Infrastructure Investment Program (IIP) regulations permit the recovery of certain capital investments, primarily related to safety and reliability, through a capital tracker recovery mechanism • ACE Energy Efficiency program allows for recovery on approximately $100M of energy efficiency programs through 2025 Illinois Maryland(1) New Jersey Pennsylvania Delaware District of Columbia (1) In August 2022, the MD PSC issued an order directing the utilities to phase out the regulatory asset treatment for the EmPOWER MD program by 2029. The phase out requires 33% of the EmPOWER MD program’s costs to be treated as O&M in 2024 with the remaining costs residing in the regulatory asset. For 2025, the O&M component of the program’s costs grows to 67%, with the full 100% of the costs treated as O&M beginning in 2026.

45 Revenue Decoupling Mitigates Load Fluctuation Impacts Non-Decoupled Load Volumes (GWh)(3)Revenue Decoupling Mitigates Load Fluctuations PECO 59% 7,880 36,764 39% 58% 41% DPL DE C&I Residential Pepco PECO ACE DPL MD ComEd DPL DE BGE Non-Decoupled Decoupled ~73% of Exelon’s distribution revenues are decoupled from volumetric risk(1,2) (1) Reflects 2022 electric and gas revenues; ComEd’s formula rate includes a mechanism that eliminates volumetric risk. Rider DSPR – Delivery Service Pricing Reconciliation will provide decoupling for calendar years 2022 and 2023 after the formula rate expires, while Rider RBA – Revenue Balancing Adjustment, which was approved by the Illinois Commerce Commission in December 2022, will provide decoupling for 2024 and beyond. ACE implemented the Conservation Incentive Program prospectively effective July 1, 2021, which eliminates the variable effects of weather and customer usage patterns for most customers. (2) Certain classes for BGE, DPL MD, Pepco and ACE are not decoupled. (3) Reflects 2022 electric volumes; remainder of volumes not captured in chart reflect public authorities or other customers.

Exelon Debt Maturity Profile(1,2) Debt Balances (as of 3/31/23)(1,2) Short-Term Debt Long-Term Debt(4) Total Debt BGE $0.2B $4.2B $4.4B ComEd $0.4B $11.7B $12.1B PECO $0.2B $4.8B $4.9B PHI - $8.6B $8.6B Corp $0.5B(3) $11.2B(4) $11.7B Exelon $1.3B $40.5B $41.8B 850 500 807 750 650 1,000 303 1,250 1,178 908 850 295 833 1,430 675 740 600 1,400 650 741 750 1,275 2,150 1,550 750 2,150 700 650 833 500 850 360 997 600 810 1,308 175 1,225 1,200 1,650 2,400 840 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 2051 2052 2053 EXC Regulated ExCorp (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium. (2) Long-term debt balances reflect 2023 Q1 10-Q GAAP financials, which include items listed in footnote 1. (3) Includes $500M of 364-day term loan maturing March 2024. (4) Includes $500M of 18-month term loans maturing in April 2024. Exelon’s weighted average long-term debt maturity is approximately 18 years ($M) As of 3/31/2023 46

47 Exelon Adjusted Operating Earnings* Sensitivities Interest Rate Sensitivity to +50bp 2023E 2024E 30-Year US Treasury Yield (1) $0.02 $0.00 Cost of Debt (2) $(0.00) $(0.01) Exelon Consolidated Effective Tax Rate 16.5% 8.9% Exelon Consolidated Cash Tax Rate 9.2% 8.3% (1) Reflects full year impact to a +50bp increase on the 30-Year US Treasury Yield impacting ComEd’s ROE net of Corporate 30-year swap impacting Exelon’s adjusted operating earnings* as of 3/31/2023. Beyond 2023, Exelon’s sensitivity relates to other ComEd long-term regulatory assets tied to interest rates, including Energy Efficiency and the Solar Rebate Program. As of 3/31/2023, Corporate entered into ~$4.1B of 30-year swaps. (2) Reflects full year impact to a +50bp increase on Corporate debt net of pre-issuance hedges and floating-to-fixed interest rate swaps as of 3/31/2023. Through 3/31/2023, Corporate entered into $130M of pre-issuance hedges through interest rate swaps.

48 Reconciliation of Non-GAAP Measures

49 Projected GAAP to Operating Adjustments • Exelon’s projected 2023 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: – Certain costs related to a change in environmental liabilities; – Costs related to a change in ComEd’s FERC audit liability; – Costs related to the separation; and – Other items not directly related to the ongoing operations of the business.

50 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 +/- 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​

51 2022 GAAP EPS Reconciliation Twelve Months Ended December 31, 2022(1) ComEd PECO BGE PHI Other Exelon 2022 GAAP Earnings (Loss) from Continuing Operations Per Share $0.93 $0.58 $0.39 $0.62 ($0.44) $2.08 Asset Impairments - - 0.04 - - 0.04 Separation costs 0.01 - - 0.01 - 0.02 Income tax-related adjustments - 0.04 - - 0.08 0.12 2022 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.94 $0.63 $0.43 $0.62 ($0.35) $2.27 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. (1) Other and Exelon include certain BSC costs that were historically allocated to ExGen for January 2022 but are presented as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules. (2) Other and Exelon amounts are revised from amounts previously reported to reflect only Exelon continuing operations and include certain BSC costs that were historically allocated to ExGen but are presented as part of continuing operations in Exelon’s results as these costs do not qualify as expenses of the discontinued operations per the accounting rules. Twelve Months Ended December 31, 2021(1,2) ComEd PECO BGE PHI Other Exelon 2021 GAAP Earnings (Loss) from Continuing Operations Per Share $0.76 $0.51 $0.42 $0.57 ($0.61) $1.65 COVID-19 Direct Costs - - - - - 0.01 Acquisition related costs - - - - 0.02 0.02 ERP System Implementation - - - - 0.01 0.01 Cost Management Program - - - - - 0.01 Separation costs 0.01 0.01 0.01 0.01 0.02 0.06 Income Tax-Related Adjustments - - - 0.03 0.03 0.06 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.77 $0.53 $0.43 $0.62 ($0.52) $1.83

52 GAAP to Non-GAAP Reconciliations Exelon Operating TTM ROE Reconciliation ($M)(1) 2016 2017 2018 2019 2020 2021 2022 Net Income (GAAP) $1,103 $1,704 $1,836 $2,065 $1,737 $2,225 $2,501 Operating Exclusions $461 ($24) $32 $30 $246 $82 $96 Adjusted Operating Earnings $1,564 $1,680 $1,869 $2,095 $1,984 $2,307 $2,596 Average Equity (2) $16,523 $17,779 $19,367 $20,913 $22,690 $24,967 $27,479 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.5% 9.4% 9.6% 10.0% 8.7% 9.2% 9.4% (1) Represents the twelve-month periods December 31, 2016-2022 for Exelon’s utilities (excludes Corp and PHI Corp). Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Components may not reconcile to other SEC filings due to rounding. (2) Reflects simple average book equity for Exelon’s utilities less goodwill at ComEd and PHI. (3) Reflects utility O&M which includes allocated costs from the shared services company; numbers rounded to the nearest $25M and may not sum due to rounding. Exelon Adjusted O&M Reconciliation ($M)(3) 2016 2017 2018 2019 2020 2021 2022 2023 GAAP O&M $4,300 $4,025 $4,150 $4,000 $4,375 $4,200 $4,475 $4,500 Regulatory Required O&M ($175) ($300) ($200) ($175) ($175) ($175) ($250) ($275) Operating Exclusions ($400) - ($50) ($50) ($275) ($75) ($75) ($25) Adjusted O&M (Non-GAAP) $3,725 $3,725 $3,900 $3,800 $3,950 $3,950 $4,150 $4,200

Thank you Please direct all questions to the Exelon Investor Relations team:  InvestorRelations@ExelonCorp.com  312-394-2345