Earnings Conference Call Third Quarter 2021 November 3, 2021

2 Q3 2021 Earnings Release Slides 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 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’ Third Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Nov. 3, 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 15, 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 Q3 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. • Adjusted operating revenues exclude the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices • Adjusted purchased power and fuel excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices 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 Q3 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 32 of this presentation.

5 Q3 2021 Earnings Release Slides Third Quarter Results • Passage of clean energy legislation in Illinois • Announced continued operation of Byron and Dresden nuclear stations • Completed the acquisition of EDF’s ownership stake of CENG nuclear plants • FERC approved separation of utility and generation businesses • Awarded DOE grant to support hydrogen production project at Nine Mile Point nuclear station • Delmarva DE received order in its electric distribution rate case • Pepco filed 5-Year Action Plan to support D.C.’s clean energy and climate goals • Exelon launched $36 million Racial Equity Capital Fund and $3 million Exelon HBCU Corporate Scholars Program • ComEd, PECO and BGE named to Site Selection Magazine’s annual list of top 20 utilities in economic development Q3 2021 EPS Results Q3 2021 Highlights/Key Developments $0.22 $0.23 $0.27 $0.28 $0.11 $0.12 $0.62 $0.44 Q3 Adjusted Operating Earnings* $0.04 Q3 GAAP Earnings ($0.04) ExGen $0.04BGE ($0.01) PECO PHI ComEd HoldCo $1.23 $1.09 Note: Amounts may not sum due to rounding

6 Q3 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem. Nuclear operations prior to Q3 2021 reflect Exelon’s 50.01% ownership share of the CENG Joint Venture. Reflects 100% ownership of CENG beginning August 7, 2021. Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q3 2021 Nuclear Capacity Factor: 96.0% ― Owned and operated Q3 2021 production of 40.5 TWh • Q3 2021 Power Dispatch Match: 99.4% • Q3 2021 Wind/Solar Energy Capture: 95.8% 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 20Q3 19 T W h rs Q4 19 Q4 20Q2 20 Q3 20 Q1 21 Q2 21 Q3 21 Capacity FactorTWhrs Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― All utilities delivered top decile SAIFI performance, and ComEd scored in the top decile in CAIDI • Each utility continued to deliver on key customer operations metrics: ― BGE, ComEd and PECO achieved top decile performance in customer satisfaction ― PHI recorded top decile performance in abandon rate • BGE, PECO and PHI remained top decile in gas odor response • Focused on improving safety at BGE, ComEd and PECO

7 Q3 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones Approved? New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention were due June 8, 2021 • Notice of Impending Settlement Negotiations issued on October 25, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention were due May 13, 2021 • Approved on August 24, 2021 ✓ Nuclear Regulatory Commission (NRC) February 25, 2021 • Comments were due June 23, 2021 • Deadline to request hearing closed July 12, 2021(1) • Updated financials and decommissioning funding status submitted September 29, 2021 • Estimated approval by November 30, 2021 • Named CEOs and direct reports, including CFOs, for Exelon and Constellation • Separation planning and preparation continues • Below is the current status of the regulatory filings: (1) Hearing requests may still be pending and resolved later, but approval will be subject to modification by Commission through hearing process

8 Q3 2021 Earnings Release Slides $0.23 $0.28 $0.12 $0.44 ComEd $0.04 ($0.01) ExGen PHI Q3 2021 BGE PECO HoldCo $1.09 Third Quarter Adjusted Operating Earnings* Results and Full Year Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M Narrowing 2021 Adjusted Operating Earnings* to $2.70 - $2.90 per share(1) 2021 Adjusted Operating EPS* Guidance Q3 2021 Adjusted Operating EPS* Results $0.45 - $0.55 ($0.25) $0.55 - $0.75 2021 Revised Guidance $0.40 - $0.50 $0.60 - $0.70 $0.75 - $0.85 ExGen BGE PECO PHI ComEd HoldCo $2.70 - $2.90(1) $0.66

9 Q3 2021 Earnings Release Slides Q3 2021 QTD Adjusted Operating Earnings* Waterfall $1.04 $1.09 $0.05 ComEd PECO2020 ($0.02)$0.03 ($0.02) BGE PHI ($0.03) ExGen(5) $0.04 Corp 2021 ($0.09) Net Unrealized and Realized Losses on Equity Investments ($0.03) Capacity Revenues ($0.02) Nuclear Outages(3) $0.06 Higher Realized NDT Fund Gains $0.02 ZEC Revenues $0.03 Other $0.05 Distribution and Transmission Rates $0.01 Storm Costs(2) ($0.01) Depreciation and Amortization 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) At PECO, primarily reflects a net increase in storm costs resulting from storms in the third quarter of 2021, partially offset by the absence of the August 2020 storms, net of tax repairs. At PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. (3) Reflects revenue and operating and maintenance expense impacts of higher nuclear outage days in 2021, excluding Salem (4) Reflects the reversal of part of the tax expense recorded in the first quarter due to the loss before income taxes at ExGen resulting from the February 2021 extreme cold weather event (5) Drivers reflect CENG ownership at 100% ($0.02) Storm Costs(2) $0.01 Distribution Rates ($0.01) Depreciation and Amortization ($0.02) Other $0.02 Distribution Investment(1) $0.01 Other $0.04 Income Taxes(4)

10 Q3 2021 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% 8.9% 9.4% 9.3% Q4 2019Q3 2019 Q3 2021Q1 2020Q3 2018 Q2 2019Q1 2019Q4 2018 Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Note: Represents the twelve-month periods ending September 30, 2018-2021, June 30, 2019-2021, March 31, 2019-2021 and December 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Exelon Utilities’ Consolidated TTM Earned ROE* remains within our 9-10% targeted range

11 Q3 2021 Earnings Release Slides Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Revenue Requirement Requested ROE / Equity Ratio Expected Order $41.0M (1,2) 9.60% / 50.21% Jul 14, 2021 $13.5M (1,3) 9.60% / 50.37% Sep 15, 2021 (4) $132.0M (1) 10.95% / 53.41% Dec 2021 $45.8M (1,5) 7.36% / 48.70% Dec 2021 $28.8M (1) 10.10% / 50.61% Mar 30, 2022 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) Reflects annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits. (3) Requested revenue requirement excludes the transfer of $3.2M 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. (4) The DPSC issued a minute order on September 15, 2021 with new rates effective on September 17, 2021. The final order with further justification is expected shortly. (5) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case. DPL DE Electric ACE 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 PECO Electric ComEd RT EH FO RT EH IB RB FO FOSA CF FODPL MD SA FO IT RT EH IB

12 Q3 2021 Earnings Release Slides Exelon Utilities Path to Clean: Advancing Energy Efficiency Driving Emissions Reductions Reducing Customer Energy Consumption Supporting Customer Affordability ➢ Helped our customers save 22.3 million MWhs of electricity in 2020 ➢ Behavioral programs notify customers about atypical energy use and available load curtailment programs ➢ Hourly pricing and smart usage rewards programs help customers manage costs during peak-demand hours Developing Innovative Solutions For Customers Incentivizing Efficiency Upgrades Promoting the Expansion of Energy Efficiency Offerings Exelon Utilities’ energy efficiency investments are helping our customers and communities reduce emissions and save money ➢ ComEd, BGE and PECO were recognized as top utilities in the nation for efficiency by the American Council for an Energy-Efficient Economy in 2020 ➢ Avoided 8.1 million mtCO2e emissions in 2020 ➢ Developing strategies to deploy next generation technologies and explore business models through research & development and other pilot programs ➢ Market development initiatives grow the diversity of our partners and vendors ➢ Energy audits assess customer efficiency and recommend usage reduction remediation measures ➢ Offer discounts, rebates, and other incentives to install higher- efficiency equipment and controls ➢ Working with stakeholders to expand business, residential and low-income offerings that are needed to achieve state targets ➢ All six utility jurisdictions have voluntary or mandated targets to increase annual energy savings

13 Q3 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2021 market conditions (5) 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. Recent Developments • 2021 Total Gross Margin* is projected to be $500M higher primarily due to acquisition of EDF’s ownership stake of CENG nuclear plants and the reversal of the Byron and Dresden retirements – Executed $200M of Power New Business and $50M of Non-Power New Business September 30, 2021 Change from June 30, 2021 Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2) (including South, West, New England, Canada hedged gross margin) $5,850 $1,600 Capacity and ZEC Revenues (2) $1,900 $100 Mark-to-Market of Hedges (2,3) $(1,100) $(1,000) Power New Business / To Go $50 $(200) Non-Power Margins Executed $400 $50 Non-Power New Business / To Go $100 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4) $7,200 $500 Estimated Gross Margin Impact of February Weather Event (5) $(950) - Total Gross Margin* $6,250 $500

14 Q3 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 Q3 2021 Earnings Release Slides Additional Disclosures

16 Q3 2021 Earnings Release Slides Q3 2021 YTD Adjusted Operating Earnings* Waterfall $1.92 $0.07 $0.01 2020 BGE $0.10 PECOComEd $0.12 PHI ($0.78) ExGen(7) ($0.06) Corp 2021 $2.46 ($0.80) Market and Portfolio Conditions(3) ($0.13) Income Taxes(4) ($0.04) Credit Loss Expense(3) $0.17 Higher Realized NDT Fund Gains $0.06 Nuclear Outages(5) $0.05 ZEC Revenues $0.02 Nuclear Fuel Costs ($0.11) Other(6) $0.08 Distribution and Transmission Rates $0.02 Favorable Weather and Load $0.02 Storm Costs(2) $0.01 Credit Loss Expense ($0.02) Depreciation and Amortization $0.01 Other 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) At PECO, primarily reflects a net decrease in storm costs resulting from the absence of the June and August 2020 storms, net of tax repairs, partially offset by storm costs in 2021. At PHI, primarily reflects the absence of costs in 2021 due to the August 2020 storms. (3) Primarily reflects the impacts of the February 2021 extreme cold weather event (4) ($0.05) at ExGen and the ($0.04) 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 continue to reverse by the end of the year. ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (5) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (6) Primarily reflects the elimination of activity attributable to noncontrolling interest of ($0.16), primarily for CENG prior to Generation’s acquisition of Electricite de France SA’s (EDF’s) interest in CENG on August 6, 2021 (7) Drivers reflect CENG ownership at 100% $0.04 Favorable Weather and Load $0.02 Storm Costs(2) ($0.01) Depreciation and Amortization $0.02 Other $0.06 Distribution Rates ($0.02) Depreciation and Amortization ($0.01) Storm Costs ($0.02) Other $0.06 Distribution Investment(1) $0.01 Transmission Revenues $0.03 Other ($0.04) Income Taxes(4) ($0.02) Other

17 Q3 2021 Earnings Release Slides Constellation Technology Ventures’ Portfolio Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of September 30, 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) transaction closed in Q4 2020. ChargePoint (SPAC) transaction closed in Q1 2021. STEM (SPAC) and Proterra (SPAC) transactions closed in Q2 2021. 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 Unmanned aerial vehicle software control platform Non-invasive energy data collection and reporting Investing in venture stage energy technology companies(1) that can provide new solutions to Exelon and its customers

18 Q3 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 Q3 2021 10-Q GAAP financials, which include items listed in footnote 1 (3) Includes $258M of legacy CEG debt in 2032 As of 9/30/2021 ($M) 850 833 807 750 360 997 303 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 2025 1,178 1,023 2021 1,150 2026 2049 2,150 2023 20242022 2051 1,225 20412027 2028 2029 1,400 1,250 2030 2031 2032 2033 2034 2035 2039 1,430 2036 2037 2038 1,550 2040 2042 2043 204620452044 1,200 1,275 2047 2048 1,650 2050 2,150 EXC RegulatedPHI Holdco ExGen(3) ExCorp Exelon Long-Term Debt Maturity Profile(1,2) BGE 4.0B ComEd 10.0B PECO 4.4B PHI 7.5B ExGen recourse (3) 4.3B ExGen non-recourse 1.8B HoldCo 7.1B Consolidated 39.0B LT Debt Balances (as of 9/30/21) (1,2)

19 Q3 2021 Earnings Release Slides Exelon Utilities

20 Q3 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 (NJBPU) to increase distribution base rates • July 14, 2021, the NJBPU approved the settlement with new rates effective on January 1, 2022 • No rate increases to customers until January 1, 2022 due to the acceleration of certain tax benefits Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Common Equity Ratio 50.21% Rate of Return ROE: 9.60%; ROR: 6.99% Rate Base (Adjusted) $1.8B Revenue Requirement Increase $41.0M(1,2) Residential Total Bill % Increase 3.3% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 7/2/2021 12/9/2020 Settlement agreement Commission order 7/14/2021 (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 annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits.

21 Q3 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 • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 • September 15, 2021, the DPSC issued a minute order with new rates effective on September 17, 2021. The final order with further justification is expected shortly. 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) $900.0M Revenue Requirement Increase $13.5M(1,2) Residential Total Bill % Increase 2.4% 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 Filed rate case 3/6/2020 9/9/2020Intervenor testimony 10/26/2020 2/10/2021 - 2/15/2021 Rebuttal testimony 9/15/2021 Evidentiary hearings 3/17/2021 5/12/2021Reply briefs Commission order Initial briefs (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 $3.2M 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.

22 Q3 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • 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 • September 15, 2021, PECO filed a Joint Petition for Settlement of Rate Investigation, which included a revenue requirement increase of $132M, but no stipulation on ROE and Equity Ratio 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 Revenue Requirement Increase $132.0M(1) Residential Total Bill % Increase 6.6% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb 9/15/2021 Rebuttal testimony 7/22/2021 Commission order expected Settlement agreement 12/2021 3/30/2021Filed rate case 6/28/2021Intervenor testimony 8/11/2021Evidentiary hearings (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings

23 Q3 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 • A final order is expected in early December 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 $45.8M(1,2) Residential Total Bill % Increase 0.2% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs Reply briefs 12/2021Commission order expected 10/1/2021 Filed rate case 4/16/2021 9/13/2021Evidentiary hearings Intervenor testimony 6/30/2021 7/28/2021Rebuttal testimony 10/15/2021 (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 in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case.

24 Q3 2021 Earnings Release Slides Rate Case Filing Details Notes Case No. 9670 • September 1, 2021, Delmarva Power filed an application with the Maryland Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • Request is driven by $18.3M of higher depreciation expense related to the Company’s updated depreciation study and continued investments in electric distribution system to maintain and increase reliability and customer service Test Year October 1, 2020 – September 30, 2021 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.61% Proposed Rate of Return ROE: 10.10%; ROR: 6.90% Proposed Rate Base (Adjusted) $930.1M Requested Revenue Requirement Increase $28.8M(1) Residential Total Bill % Increase 5.0% Delmarva MD Distribution Rate Case Filing Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Rebuttal testimony 3/30/2022 Evidentiary hearings 2/9/2022 12/2/2021 Initial briefs Filed rate case 1/19/2022 - 1/24/2022 Commission order expected PULJ proposed order expected(2) 9/1/2021 Intervenor testimony 12/23/2021 2/28/2022 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Public Utility Law Judge (PULJ)

25 Q3 2021 Earnings Release Slides Exelon Generation Disclosures September 30, 2021

26 Q3 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

27 Q3 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*

28 Q3 2021 Earnings Release Slides ExGen Disclosures (1) Gross margin* categories rounded to nearest $50M (2) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2021 market conditions (5) 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. (6) Reflects full year prices based on Exelon’s portfolio hedging strategy September 30, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2) $5,850 Capacity and ZEC Revenues (2) $1,900 Mark-to-Market of Hedges (2,3) $(1,100) Power New Business / To Go $50 Non-Power Margins Executed $400 Non-Power New Business / To Go $100 Total Gross Margin* (Excluding Impact of February Weather Event) (4) $7,200 Estimated Gross Margin Impact of February Weather Event (5) $(950) Total Gross Margin* $6,250 Reference Prices (4,6) 2021 Henry Hub Natural Gas ($/MMBtu) $3.94 Midwest: NiHub ATC prices ($/MWh) $36.10 Mid-Atlantic: PJM-W ATC prices ($/MWh) $39.21 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $87.14 New York: NY Zone A ($/MWh) $31.32

29 Q3 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 13 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) Reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (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. September 30, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 183,400 Midwest 95,000 Mid-Atlantic (2) 51,500 ERCOT 16,300 New York (2) 20,600 % of Expected Generation Hedged (3) 96%-99% Midwest 96%-99% Mid-Atlantic (2) 95%-98% ERCOT 94%-97% New York (2) 95%-98% Effective Realized Energy Price ($/MWh) (4) Midwest $27.50 Mid-Atlantic (2) $34.50 New York (2) $27.50

30 Q3 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on September 30, 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; reflects Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 September 30, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu - - $1/MMBtu $10 NiHub ATC Energy Price + $5/MWh $5 - $5/MWh $(5) PJM-W ATC Energy Price + $5/MWh - - $5/MWh - NYPP Zone A ATC Energy Price + $5/MWh - - $5/MWh - Nuclear Capacity Factor +/- 1% +/- $10

31 Q3 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 xi m 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 September 30, 2021. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. $6,100 $6,350

32 Q3 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Adjusted Operating Revenues*(2,3) $19,875 Adjusted Purchased Power and Fuel*(2,3) $(13,175) Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Non-GAAP) $6,250 (1) All amounts rounded to the nearest $25M (2) Reflects Exelon’s 50.01% ownership share of CENG from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (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) O&M, TOTI and Depreciation & Amortization reflect Exelon’s 50.01% ownership share of CENG Joint venture from January 1 to August 6, 2021 and Exelon’s full ownership share beginning August 7, 2021 (6) 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 (7) 2021 Adjusted O&M* includes $175M 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 (8) 2021 TOTI excludes gross receipts tax of $100M Key ExGen Modeling Inputs (in $M)(1,5) 2021 Other(6) $350 Adjusted O&M*(7) $(4,075) Taxes Other Than Income (TOTI)(8) $(350) Depreciation & Amortization* $(1,025) Interest Expense $(300) Effective Tax Rate 25.0%

33 Q3 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

34 Q3 2021 Earnings Release Slides Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.22 $0.11 $0.04 $0.27 $0.62 ($0.04) $1.23 Mark-to-market impact of economic hedging activities - - - - (0.58) 0.01 (0.57) Unrealized losses related to NDT funds - - - - 0.06 - 0.06 Asset impairments - - - - 0.03 - 0.03 Plant retirements and divestitures - - - - 0.22 - 0.22 Cost management program - - - - - - 0.01 COVID-19 direct costs - - - - - - 0.01 Asset retirement obligation - - - - (0.04) - (0.04) Acquisition related costs - - - - 0.01 - 0.01 Planned separation costs - - - - 0.01 - 0.03 Costs related to suspension of contractual offset - - - - 0.11 - 0.11 Income tax-related adjustments - - - - - 0.02 0.02 Noncontrolling interests - - - - (0.02) - (0.02) 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.23 $0.12 $0.04 $0.28 $0.44 ($0.01) $1.09 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

35 Q3 2021 Earnings Release Slides Q3 QTD GAAP EPS Reconciliation (continued) Three Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.20 $0.14 $0.05 $0.22 $0.05 ($0.16) $0.51 Mark-to-market impact of economic hedging activities - - - - (0.20) 0.01 (0.19) Unrealized gains related to NDT funds - - - - (0.18) - (0.18) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.34 - 0.34 Cost management program - - - - 0.01 - 0.02 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - - - - 0.01 - 0.01 Income tax-related adjustments - - - - (0.03) 0.09 0.06 Noncontrolling interests - - - - 0.06 - 0.06 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.14 $0.06 $0.23 $0.47 ($0.05) $1.04 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

36 Q3 2021 Earnings Release Slides Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.62 $0.39 $0.30 $0.55 ($0.25) ($0.26) $1.34 Mark-to-market impact of economic hedging activities - - - - (0.95) 0.01 (0.94) Unrealized gains related to NDT funds - - - - (0.03) - (0.03) Asset impairments - - - - 0.41 - 0.41 Plant retirements and divestitures - - - - 0.88 - 0.88 Cost management program - - - - 0.01 - 0.01 Change in environmental liabilities - - - - 0.01 - 0.01 COVID-19 direct costs - - - - 0.02 - 0.02 Asset retirement obligation - - - - (0.04) - (0.04) Acquisition related costs - - - - 0.02 - 0.02 ERP system implementation costs - - - - 0.01 - 0.01 Planned separation costs 0.01 - - 0.01 0.02 0.01 0.05 Costs related to suspension of contractual offset - - - - 0.15 - 0.15 Income tax-related adjustments - - - - - 0.02 0.02 Noncontrolling interests - - - - 0.02 - 0.02 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.63 $0.40 $0.30 $0.56 $0.26 ($0.23) $1.92 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

37 Q3 2021 Earnings Release Slides Q3 YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.31 $0.32 $0.28 $0.43 $0.58 ($0.28) $1.64 Mark-to-market impact of economic hedging activities - - - - (0.36) 0.02 (0.34) Unrealized losses related to NDT funds - - - - 0.01 - 0.01 Asset impairments 0.01 - - - 0.39 - 0.40 Plant retirements and divestitures - - - - 0.36 - 0.36 Cost management program - - - 0.01 0.03 - 0.03 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.04 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income tax-related adjustments - - - - (0.03) 0.10 0.07 Noncontrolling interests - - - - 0.02 - 0.02 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.53 $0.33 $0.29 $0.44 $1.04 ($0.17) $2.46 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.

38 Q3 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; − Asset impairments; − 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; − Costs related to the impact of suspension of contractual offset for the Byron units beginning in the second quarter of 2021 through September 15, 2021; − Asset retirement obligations; − Adjustment to deferred income taxes as a result of changes in forecasted apportionment; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.

39 Q3 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Net Income (GAAP) $1,836 $1,770 Operating Exclusions $32 $40 Adjusted Operating Earnings $1,869 $1,810 Average Equity $19,367 $18,878 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% Consolidated EU Operating TTM ROE Reconciliation ($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 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q3 2021 Q2 2021 Q1 2021 Net Income (GAAP) $2,243 $2,214 $1,841 Operating Exclusions $42 $36 $249 Adjusted Operating Earnings $2,284 $2,250 $2,090 Average Equity $24,651 $23,882 $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.3% 9.4% 8.9% Note: Represents the twelve-month periods ending September 30, 2018-2021, June 30, 2019-2021, March 31, 2019-2021 and December 31, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).

40 Q3 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $4,600 Decommissioning(2) $25 Byron and Dresden(3) $575 Asset Impairments(4) ($525) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) ($275) O&M for managed plants that are partially owned ($250) Other ($75) Adjusted O&M (Non-GAAP) $4,075 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 associated with the decision to early retire Byron and Dresden that cannot be reversed. The remaining amount primarily reflects the reversal of one-time charges resulting from the previous decision to retire Byron and Dresden. (4) Reflects an impairment in the New England asset group, an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility, and an impairment of a wind project (5) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*