Earnings Conference Call First Quarter 2021 May 5, 2021

2 Q1 2021 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain written and oral forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” 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. The factors that could cause actual results to differ materially from the forward-looking statements made by Exelon Corporation, Exelon Generation Company, LLC, 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' 2020 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 19, Commitments and Contingencies; (2) the Registrants' First Quarter 2021 Quarterly Report on Form 10-Q (to be filed on May 5, 2021) 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 14, 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 Q1 2021 Earnings Release Slides 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 costs, expenses, gains and losses and other specified items, including mark-to- market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain Constellation and Power businesses • Adjusted cash flow from operations primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net merger and acquisitions, and equity investments • Free cash flow primarily includes net cash flows from operating activities and net cash flows from investing activities excluding certain capital expenditures, net merger and acquisitions, and equity investments • 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). • EBITDA is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. • Revenue net of purchased power and fuel expense is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense 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

4 Q1 2021 Earnings Release Slides Non-GAAP Financial Measures Continued 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, except for the reconciliation for total gross margin, which appears on slide 36 of this presentation.

5 Q1 2021 Earnings Release Slides First Quarter Results • GAAP earnings of ($0.30) per share in Q1 2021 vs. $0.60 per share in Q1 2020 • Adjusted operating earnings* of ($0.06) per share in Q1 2021 vs. $0.87 per share in Q1 2020 Q1 2021 EPS Results $0.20 $0.20 $0.13 $0.13 $0.17 $0.17 $0.21 $0.22 ($0.20) ($0.20) ($0.81) ($0.58) ExGen PHI PECO BGE Q1 GAAP Earnings Q1 Adjusted Operating Earnings* ComEd HoldCo ($0.30) ($0.06) Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1)

6 Q1 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q1 2021 Nuclear Capacity Factor: 95.3% ― Owned and operated Q1 2021 production of 36.8 TWh • Q1 2021 Power Dispatch Match: 68.5% • Q1 2021 Renewables Energy Capture: 96.4% Operations Metric YTD 2021 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) (1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Abandon Rate Gas Operations Gas Odor Response No Gas Operations Fossil and Renewable Fleet Exelon Nuclear Fleet (2) 80% 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 30 32 34 36 38 40 42 44 C a p a c ity F a c to r Q1 19 T W h rs Q2 20Q4 19Q2 19 Q3 19 Q1 20 Q3 20 Q4 20 Q1 21 TWhrs Capacity Factor Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― BGE, ComEd and PHI delivered top decile CAIDI performance, while ComEd scored in the top decile in SAIFI • Each utility continued to deliver on key customer operations metrics: ― BGE and PECO recorded top decile performance in Customer Satisfaction ― ComEd and PHI achieved top decile performance in Abandon Rate • BGE, PECO and PHI performed in top decile in Gas Odor Response

7 Q1 2021 Earnings Release Slides Policy Developments Supporting a Clean Energy Economy Biden Administration • Set nationally determined contribution (NDC) to meet Paris Climate Accords of 50-52% reduction in greenhouse gas emissions from 2005 levels by 2030 • American Jobs Plan: – A national clean energy standard targeting 100% clean electricity by 2035, age and technology neutral – Grant and incentive program for state and local government and private sector to build 500,000 EV charging stations by 2030 – Direct pay clean energy production and investment tax credits – Incentives for 20 GWs of high voltage transmission and creation of Grid Deployment Authority at DOE to help with siting Illinois Clean Energy Legislation • 6 major bills introduced to drive decarbonization and grid modernization • Provisions of the various bills include: – Carbon mitigation credits – FRR authorization – Carbon pricing mechanism – Transition to traditional ratemaking – Electrification provisions – Expansion of RPS budget Pennsylvania Clean Transportation Infrastructure Act • Establishes a state goal of increasing electrification by 50% over currently forecasted levels • Requires development of regional electrification infrastructure frameworks • Directs utilities to file infrastructure investment plans with the PUC and authorizes cost recovery

8 Q1 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention due May 24, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention due May 13, 2021 Nuclear Regulatory Commission (NRC) February 25, 2021 • Intervention due May 24, 2021 • Comments due June 2, 2021 • Estimated completion date by November 30, 2021 • Separation planning and preparation continues • Below is the current status of the regulatory filings:

9 Q1 2021 Earnings Release Slides $0.20 $0.13 $0.17 $0.22 ($0.20) ($0.58) PHI Q1 2021 BGE HoldCo PECO ComEd ExGen First Quarter Adjusted Operating Earnings* Drivers Exelon Utilities • Utilities performed well in Q1 driven by continued investment and distribution rate case outcomes • Slightly milder than normal weather in the Mid-Atlantic • 30-Year Treasury rate rose since year-end Exelon Generation • February extreme cold weather event • Strong nuclear performance • New business execution • Market prices up since year-end HoldCo • Timing of tax expense (will reverse by year- end) ($0.06) Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1) Financial HighlightsQ1 2021 Adjusted Operating EPS* Results

10 Q1 2021 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.3% 9.4% 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% 8.9% Q3 2019 Q4 2020Q4 2018Q1 2018 Q3 2018Q2 2018 Q2 2019Q1 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Q1 2021 Note: Represents the twelve-month periods ending March 31, 2018-2021, December 31, 2018-2020, September 30, 2018-2020, and June 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Low interest rates, storms and unfavorable weather have pressured Exelon Utilities’ Consolidated TTM Earned ROE*

11 Q1 2021 Earnings Release Slides Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Revenue Requirement Requested ROE / Equity Ratio Expected Order $2.3M (1,2) 9.60% / 50.37% Jan 6, 2021 $135.9M (1,3) 3-Year MYP 9.70% / 50.68% Q2 2021 $22.9M (1,4) 10.30% / 50.37% Q3 2021 $104.1M (1,5) 3-Year MYP 10.20% / 50.50% Jun 28, 2021 $68.7M (1) 10.95% / 53.38% Jun 2021 $66.8M (1) 10.30% / 50.21% Q4 2021 $246.0M (1) 10.95% / 53.41% Dec 2021 $51.2M (1) 7.36% / 48.70% Dec 2021 Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms 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) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund. Settlement was filed with the DPSC on December 18, 2020. The DPSC approved the settlement on January 6, 2021 with new rates effective on February 1, 2021. (3) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. (4) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021. (5) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $52.2M and $51.8M with rates effective April 1, 2023 and April 1, 2024, respectively. (6) As allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund (7) Reflects anticipated schedule; actual dates will be determined by ALJ at prehearing conference Pepco DC DPL DE Electric EH Pepco MD RT EH PECO Gas FO FO IB RB IT RT EH RBIB ACE(6) RTIT EH DPL DE Gas FO 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 FO PECO(7) Electric FO ComEd(7) CF RTIT EH IB RB CF FO FO IB RB RBIB RTIT EH IB RB FO

12 Q1 2021 Earnings Release Slides Exelon Utilities Path to Clean: Enabling Vehicle Electrification Advancing Accessibility of EV Infrastructure • Working with stakeholders to evolve legislation, regulations, and EV programs that promote the expansion of infrastructure and remove barriers to adoption • 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 • Offering rebates and incentives to support the development of make-ready infrastructure and/or installation of eligible smart chargers Enabling Customer Affordability • Offering various rate programs designed to manage the cost of EV charging consumption and minimize the impact of EV load growth to the distribution grid – EV-Only Time of Use and hourly pricing rates bill residential customers at reduced, off-peak charging rates – Temporary reduction in demand charges available to qualified customers and specified use cases – Renewable option allows customers to offset their energy consumption with Renewable Energy Credits, providing a carbon- free charging alternative Increasing Customer Awareness and Adoption • Investing in education and outreach programs to inform customers of the benefits of vehicle electrification, the availability of EV technologies, and utility-specific programs and offerings Helping our jurisdictions achieve climate and zero-emission vehicle goals, improve air quality in the region, and prepare for the economic opportunities connected to the growing EV market 2 states with zero-emission vehicle goals 4 jurisdictions with approved EV Programs 30% by 2025 and 50% by 2030 Exelon Utilities’ light and heavy-duty vehicle fleet electrification goal

13 Q1 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (7) Reflects variance to December 31, 2020 estimates adjusted for February’s weather event (as presented on Q4 earnings call) Recent Developments • Excluding the impacts of the February weather event, 2021 Total Gross Margin* is projected to be flat primarily due to increased power prices and the execution of New Business, offset by our hedges – Executed $100M of Power New Business and $50M of Non-Power New Business for 2021 • Estimating an incremental $(150)M of impacts associated with the February weather event relative to the range provided on our Q4 call March 31, 2021 Change from December 31, 2020 (7) Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2,5) (including South, West, New England, Canada hedged gross margin) $3,500 $300 Capacity and ZEC Revenues (2) $1,800 - Mark-to-Market of Hedges (2,3) $500 $(200) Power New Business / To Go $400 $(100) Non-Power Margins Executed $300 $50 Non-Power New Business / To Go $200 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 - Estimated Gross Margin Impact of February Weather Event (6) $(950) $(150) Total Gross Margin* $5,750 $(150)

14 Q1 2021 Earnings Release Slides 2021 Business Priorities and Commitments Meet or exceed our financial commitments Effectively deploy ~$6.6B of utility capex Ensure timely recovery on investments to enable customer benefits Support enactment of clean energy policies Continued demonstration of corporate responsibility Prepare for separation of businesses Maintain industry-leading operational excellence

15 Q1 2021 Earnings Release Slides Additional Disclosures

16 Q1 2021 Earnings Release Slides 2021 Guidance $0.55 - $0.85 ComEd $0.45 - $0.55 PHI $2.60 - $3.00(1) PECO HoldCo ($0.25) ExGen BGE $0.40 - $0.50 $0.55 - $0.65 $0.75 - $0.85 2021 Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 979M

17 Q1 2021 Earnings Release Slides Q1 2021 Adjusted Operating Earnings* Waterfall BGE $0.03 2020 $0.03 $0.02 ($0.14) PECOComEd $0.03 PHI ($0.90) ExGen(6) Corp 2021 $0.87 ($0.85) Market and Portfolio Conditions(2) ($0.14) Income Taxes(3) ($0.02) Credit Loss Expense(2) $0.08 Higher Realized NDT Fund Gains $0.04 Nuclear Outages(4) $0.02 Capacity Revenues ($0.03) Other(5) $0.01 Distribution Rates $0.01 Favorable Weather Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the impacts of the February 2021 extreme cold weather event (3) $(0.07) at ExGen and the $(0.12) at Corp relate to timing of tax expense driven primarily by the loss before income taxes at ExGen in the first quarter due to the February 2021 extreme cold weather event. These timing impacts will reverse by the end of the year. The remaining ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, excluding Salem (5) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (6) Drivers reflect CENG ownership at 100% $0.04 Favorable Weather and Load ($0.01) Other $0.04 Distribution Rates ($0.01) Other $0.02 Distribution Investment(1) $0.01 Other ($0.12) Income Taxes(3) ($0.02) Other ($0.06)

18 Q1 2021 Earnings Release Slides Constellation Technology Ventures’ Active Investments Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of May 5, 2021 (1) Green boxes reflect companies that have executed Initial Public Offerings (IPOs) or merger transactions with Special Purpose Acquisition Companies (SPACs). XL Fleet (SPAC) and C3.ai (IPO) transactions closed in Q4 2020. ChargePoint (SPAC) and Ouster (SPAC) transactions closed in Q1 2021. STEM (SPAC) transaction closed in Q2 2021. (2) Orange boxes reflect publicly announced SPAC merger transactions that have not yet closed Renewable PPA Marketplace Building sustainability reporting platform Electric buses for public and private mass transit HVAC optimization for SMB and C&I EV charging network and service equipment Energy storage systems and controls Residential load disaggregation platform Battery monitoring and management software EE financing and building optimization for SMB and C&I Class 2-6 HEV and PHEV fleet electrification Residential PV and EE for low-to- middle income homeowners Commercial LIDAR and fleet safety software Unmanned aerial vehicle software control platform Artificial intelligence and enterprise data management Non-invasive energy data collection and reporting Investing in venture stage energy technology companies (1,2) that can provide new solutions to Exelon and its customers

19 Q1 2021 Earnings Release Slides Exelon’s weighted average LTD maturity is approximately 16 years (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 Q1 2021 10-Q GAAP financials, which include items listed in footnote 1. On April 1, 2021, ACE retired $200M of first mortgage bonds and on April 15, 2021, HoldCo retired $300M of senior notes (3) Includes $258M of legacy CEG debt in 2032 As of 3/31/2021 ($M) 300 850 833 807 750 360 997 303 578 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 2024 2047 1,023 1,151 2021 2022 1,150 20452023 20272025 1,275 20312026 2028 20442029 1,250 2030 20332032 2034 2035 1,430 2,150 2036 1,400 2037 2038 2051 1,225 2039 2040 2043 20462041 2042 1,200 1,650 1,550 2049 2050 1,200 2048 PHI Holdco ExGen(3)EXC Regulated ExCorp Exelon Debt Maturity Profile(1,2) BGE 3.7B ComEd 9.9B PECO 4.3B PHI 7.6B ExGen recourse (3) 4.3B ExGen non-recourse 1.7B HoldCo 7.4B Consolidated 38.9B LT Debt Balances (as of 3/31/21) (1,2)

20 Q1 2021 Earnings Release Slides Exelon Utilities

21 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0150 – Per Settlement (Black Box) • February 21, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase reliability and customer service • December 18, 2020, settlement agreement was filed with the DPSC • January 6, 2021, the DPSC approved the settlement with new rates effective on February 1, 2021 Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Common Equity Ratio 50.37% Rate of Return ROE: 9.60%; ROR: 6.80% Rate Base (Adjusted) N/A Revenue Requirement Increase $2.3M(1,2) Residential Total Bill % Increase 2.0% Delmarva DE (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Intervenor testimony 10/9/2020Rebuttal testimony 9/1/2020 Filed rate case Settlement agreement Commission order 2/21/2020 12/18/2020 1/6/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund.

22 Q1 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three year multi-year plan (MYP) request with the Public Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and interconnection Distributed Energy Resources (DER) • June 1, 2020, Pepco DC filed MYP Enhanced Proposal to address impact of COVID-19. The proposal includes an offset to distribution rates allowing for no overall distribution increase until January 2022 and several customer assistance programs. Test Year January 1 – December 31 Test Period 2020, 2021, 2022 Proposed Common Equity Ratio 50.68% Proposed Rate of Return ROE: 9.70%; ROR: 7.39% 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B 2020-2022 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $72.6M, $63.3M 2020-2022 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.6%, 6.6% Pepco DC Distribution Rate Case Filing Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Intervenor testimony Commission order expected Reply briefs 5/30/2019 12/9/2020 Filed rate case 10/26/2020 - 10/30/2020 3/6/2020 Rebuttal testimony 4/8/2020 12/23/2020 Initial briefs Q2 2021 Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively.

23 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 10.30%; ROR: 7.15% Proposed Rate Base (Adjusted) $910.2M Requested Revenue Requirement Increase $22.9M(1,2) Residential Total Bill % Increase 3.3% Delmarva DE (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Reply briefs Rebuttal testimony Q3 2021 Filed rate case 2/10/2021 - 2/15/2021 9/9/2020 Evidentiary hearings Initial briefs Intervenor testimony Commission order expected 10/26/2020 3/17/2021 3/6/2020 5/12/2021 (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 $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund.

24 Q1 2021 Earnings Release Slides Multi-Year Plan Case Filing Details Notes Formal Case No. 9655 • October 26, 2020, Pepco MD filed a three-year multi-year plan (MYP) request with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • MYP proposes five tracking only Performance Incentive Mechanisms (PIMs) focused on system reliability, customer service and environmental • The proposal includes an offset to distribution rates allowing for no overall distribution increase until April 2023 Test Year April 1 – March 31 Test Period 2022, 2023, 2024 Proposed Common Equity Ratio 50.50% Proposed Rate of Return ROE: 10.20%; ROR: 7.54% 2022-2024 Proposed Rate Base (Adjusted) $2.1B, $2.4B, $2.6B 2022-2024 Requested Revenue Requirement Increase (1,2) $0.0M, $0.0M, $52.2M, $51.8M 2022-2024 Residential Total Bill % Increase (2) 0.0%, 0.0%, 4.3%, 4.1% Pepco MD Distribution Rate Case Filing Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 4/26/2021 - 4/30/2021 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Commission order expected Reply briefs 3/3/2021 3/31/2021 5/21/2021 6/1/2021 6/28/2021 (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 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $52.2M and $51.8M with rates effective April 1, 2023 and April 1, 2024, respectively.

25 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2020-3018929 • On September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase safety, reliability and customer service Test Year July 1, 2021 – June 30, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.38% Proposed Rate of Return ROE: 10.95%; ROR: 7.70% Proposed Rate Base (Adjusted) $2,462M Requested Revenue Requirement Increase $68.7M(1) Residential Total Bill % Increase 9.0% PECO (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep 9/30/2020 Intervenor testimony 1/19/2021Rebuttal testimony 12/22/2020 2/17/2021Evidentiary hearings 6/1/2021 - 6/30/2021 Filed rate case 3/3/2021Initial Briefs 3/15/2021Reply Briefs Commission order expected (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

26 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. ER20120746 • December 9, 2020, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (BPU) to increase distribution base rates • Size of ask is primarily driven by continued investments in electric distribution system to maintain and improve reliability and customer service and implementation of new technologies • Forward looking additions through August 2021 ($11.1M of revenue requirement based on 10.30% ROE) included in revenue requirement request • To address the impacts of COVID-19, ACE’s proposal includes offsets allowing for no overall distribution rate increase until January 2022 Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Proposed Common Equity Ratio 50.21% Proposed Rate of Return ROE: 10.30%; ROR: 7.34% Proposed Rate Base (Adjusted) $1.8B Requested Revenue Requirement Increase $66.8M(1,2) Residential Total Bill % Increase 6.7% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec 6/4/2021 12/9/2020 Reply Briefs Filed rate case Intervenor testimony Initial Briefs 7/2/2021 Q4 2021 Rebuttal testimony 8/10/2021 - 8/17/2021Evidentiary hearings(3) 9/17/2021 Commission order expected 9/3/2021 (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 allowed by regulations, ACE intends to put interim rates in effect on September 8, 2021, subject to refund (3) Evidentiary hearings scheduled for August 10-12, 16 and 17, 2021

27 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • On March 30, 2021, PECO filed a general base rate request with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in electric distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the local electric grid as well as to enable the advancement of clean technologies • In addition, the filing proposes COVID relief offerings for eligible residential and small business customers Test Year January 1, 2022 – December 31, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.41% Proposed Rate of Return ROE: 10.95%; ROR: 7.68% Proposed Rate Base (Adjusted) $6,386M Requested Revenue Requirement Increase $246.0M(1) Residential Total Bill % Increase 9.7% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule(2) Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Reply Briefs 9/1/2021 - 9/15/2021 Commission order expected Filed rate case 3/30/2021 Intervenor testimony 6/2021 Rebuttal testimony 12/2021 9/16/2021 - 9/30/2021 7/2021 8/2021 Initial Briefs Evidentiary hearings (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 anticipated schedule; actual dates will be determined by ALJ at prehearing conference

28 Q1 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 21-0367 • April 16, 2021, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC) seeking a $51.2M increase to distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the reliability of the grid and enable the advancement of clean technologies and renewable energy Test Year January 1, 2020 – December 31, 2020 Test Period 2020 Actual Costs + 2021 Projected Plant Additions Proposed Common Equity Ratio 48.70% Proposed Rate of Return ROE: 7.36%; ROR: 5.72% Proposed Rate Base (Adjusted) $13,035M Requested Revenue Requirement Increase $51.2M(1) Residential Total Bill % Increase 0.3% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule(2) Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs 12/2021Commission order 6/2021 4/16/2021 Intervenor testimony Rebuttal testimony 7/2021 Evidentiary hearings Reply briefs 8/2021 9/2021 9/2021 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 (2) Reflects anticipated schedule; actual dates will be determined by ALJ at prehearing conference

29 Q1 2021 Earnings Release Slides Exelon Generation Disclosures March 31, 2021

30 Q1 2021 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d g e d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over TimeAlign Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure

31 Q1 2021 Earnings Release Slides Components of Gross Margin* Categories Open Gross Margin* •Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin*; no expected generation, hedge %, EREP or reference prices provided for this region (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) Proprietary trading gross margins* will generally remain within “Non Power” New Business category and only move to “Non Power” Executed category upon management discretion (4) Gross margin* for these businesses are net of direct “cost of sales” (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*

32 Q1 2021 Earnings Release Slides ExGen Disclosures (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. March 31, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2,5) $3,500 Capacity and ZEC Revenues (2) $1,800 Mark-to-Market of Hedges (2,3) $500 Power New Business / To Go $400 Non-Power Margins Executed $300 Non-Power New Business / To Go $200 Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 Estimated Gross Margin Impact of February Weather Event (6) $(950) Total Gross Margin* $5,750 Reference Prices (4) 2021 Henry Hub Natural Gas ($/MMBtu) $2.71 Midwest: NiHub ATC prices ($/MWh) $25.03 Mid-Atlantic: PJM-W ATC prices ($/MWh) $27.35 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $90.78 New York: NY Zone A ($/MWh) $22.95

33 Q1 2021 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factor of 94.5% in 2021 at Exelon-operated nuclear plants, at ownership. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively March 31, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 170,900 Midwest (5) 88,100 Mid-Atlantic (2) 47,900 ERCOT 18,200 New York (2) 16,700 % of Expected Generation Hedged (3) 94%-97% Midwest (5) 94%-97% Mid-Atlantic (2) 98%-101% ERCOT 93%-96% New York (2) 83%-86% Effective Realized Energy Price ($/MWh) (4) Midwest (5) $26.00 Mid-Atlantic (2) $33.50 New York (2) $26.50

34 Q1 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on March 31, 2021 market conditions and hedged position; gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions; excludes EDF’s equity share of CENG Joint Venture March 31, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $35 - $1/MMBtu $(25) NiHub ATC Energy Price + $5/MWh $(5) - $5/MWh $5 PJM-W ATC Energy Price + $5/MWh $(15) - $5/MWh $20 NYPP Zone A ATC Energy Price + $5/MWh - - $5/MWh - Nuclear Capacity Factor +/- 1% +/- $20

35 Q1 2021 Earnings Release Slides 5,000 5,500 6,000 6,500 7,000 2021 ExGen Hedged Gross Margin* Upside/Risk A p p ro x im a te G ro s s M a rg in * ( $ m il li o n )( 1 ) (1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin* range is based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of March 31, 2021. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. $5,600 $5,850

36 Q1 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,150 Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Excluding Impact of February Weather Event) (Non-GAAP) $6,700 Estimated Gross Margin Impact of February Weather Event(5) $(950) Total Gross Margin* (Non-GAAP) $5,750 (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) Reflects the midpoint of the initial gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (6) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (7) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, includes the minority interest in ExGen Renewables JV, and unrealized gains or losses from equity investments (8) 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time and a preliminary estimate of bad debt associated with the February weather event that is subject to change (9) 2021 TOTI excludes gross receipts tax of $125M Key ExGen Modeling Inputs (in $M)(1,6) 2021 Other(7) $400 Adjusted O&M*(8) $(3,700) Taxes Other Than Income (TOTI)(9) $(350) Depreciation & Amortization* $(1,000) Interest Expense $(300) Effective Tax Rate 25.0%

37 Q1 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

38 Q1 2021 Earnings Release Slides Q1 GAAP EPS Reconciliation Three Months Ended March 31, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.20 $0.17 $0.21 $0.13 ($0.81) ($0.20) ($0.30) Mark-to-market impact of economic hedging activities - - - - (0.14) - (0.14) Unrealized losses related to NDT funds - - - - 0.04 - 0.04 Plant retirements and divestitures - - - - 0.32 - 0.32 COVID-19 direct costs - - - - 0.01 - 0.01 Acquisition related costs - - - - 0.01 - 0.01 ERP system implementation costs - - - - - - 0.01 Planned separation costs - - - - - - 0.01 Noncontrolling interests - - - - (0.02) - (0.02) 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.17 $0.22 $0.13 ($0.58) ($0.20) ($0.06) Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

39 Q1 2021 Earnings Release Slides Q1 GAAP EPS Reconciliation (continued) 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 March 31, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.17 $0.14 $0.19 $0.11 $0.05 ($0.06) $0.60 Mark-to-market impact of economic hedging activities - - - - (0.10) - (0.10) Unrealized losses related to NDT funds - - - - 0.50 - 0.50 Plant retirements and divestitures - - - - 0.01 - 0.01 Cost management program - - - - 0.01 - 0.01 Noncontrolling interests - - - - (0.15) - (0.15) 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.17 $0.14 $0.19 $0.11 $0.32 ($0.06) $0.87

40 Q1 2021 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2021 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Certain costs related to plant retirements and divestitures; − Certain costs incurred to achieve cost management program savings; − Direct costs related to the novel coronavirus (COVID-19) pandemic; − Certain acquisition-related costs; − Costs related to a multi-year Enterprise Resource Program (ERP) system implementation; − Costs related to the planned separation; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

41 Q1 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Q1 2018 Net Income (GAAP) $1,836 $1,770 $1,724 $1,643 Operating Exclusions $32 $40 $13 $32 Adjusted Operating Earnings $1,869 $1,810 $1,737 $1,675 Average Equity $19,367 $18,878 $18,467 $17,969 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% 9.3% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2019 Q3 2019 Q2 2019 Q1 2019 Net Income (GAAP) $2,065 $2,037 $2,011 $1,967 Operating Exclusions $30 $33 $31 $33 Adjusted Operating Earnings $2,095 $2,070 $2,042 $1,999 Average Equity $20,913 $20,500 $20,111 $19,639 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 10.0% 10.1% 10.2% 10.2% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2020 Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,737 1,747 $1,728 $2,060 Operating Exclusions 246 243 $254 $31 Adjusted Operating Earnings 1,984 1,990 $1,982 $2,091 Average Equity 22,690 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Note: Represents the twelve-month periods ending March 31, 2018-2021, December 31, 2018-2020, September 30, 2018-2020, and June 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Consolidated EU Operating TTM ROE Reconciliation ($M) Q1 2021 Net Income (GAAP) $1,841 Operating Exclusions $249 Adjusted Operating Earnings $2,090 Average Equity $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.9%

42 Q1 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $3,925 Decommissioning(2) $50 Byron and Dresden Retirements(3) $475 Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) ($275) O&M for managed plants that are partially owned ($400) Other ($75) Adjusted O&M (Non-GAAP) $3,700 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) Includes $500M of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*