Earnings Conference Call Fourth Quarter 2019 February 11, 2020

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. 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) Exelon’s 2018 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 22, Commitments and Contingencies; (2) Exelon’s Third Quarter 2019 Quarterly Report on Form 10-Q 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 16, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. 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. 2 Q4 2019 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 3 Q4 2019 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 53 of this presentation. 4 Q4 2019 Earnings Release Slides

2019 Accomplishments Maintain industry leading operational excellence • Best on record Customer Satisfaction at all utilities • ComEd had its best performance ever in both CAIDI and SAIFI; PHI continued to improve its reliability scores in 2019, setting best on record results in SAIFI • 2019 capacity factor of 95.7%(1) was the highest ever, supporting 155 TWHs of nuclear production and avoiding ~81M metric tonnes of carbon dioxide • 79% customer renewal rate and 36% new customer win rate for Constellation’s retail power business Meet or exceed our financial commitments • Delivered GAAP earnings of $3.01 per share and adjusted (non-GAAP) operating earnings of $3.22 per share • Exelon Corp. and all of its subsidiaries received credit upgrades • Committed to $100M of additional cost reductions at ExGen on the Q3 2019 earnings call Effectively deploy ~$5.3B of 2019 utility capex • Invested approximately $5.5B to replace aging infrastructure and improve reliability for the benefit of customers Advocate for policies to enable the utility of the future • Maryland PSC approved alternative rate making allowing for multi-year rate plans • Pepco DC filed multi-year rate plan with DC PSC • Pennsylvania Senate passed SB596 setting state electrification goals Advance PJM energy market price formation reforms • Fast start approved by FERC • Supported PJM-filed proposal to reform reserve market and scarcity rules Preserve authority of states to enact state clean energy policies and seek fair compensation for zero-emitting nuclear plants • U.S. Supreme Court upheld IL and NY ZEC programs; NJ implemented ZEC program • Governor Wolf announced plans for Pennsylvania to join the Regional Greenhouse Gas Initiative Grow dividend at 5% rate • Increased the dividend to $1.45 from $1.38 per share Continued commitment to corporate responsibility • Exelon employees volunteered a record-breaking 250,790 hours and donated approximately $12 million • Exelon Foundation, Exelon’s family of companies and our employees donated nearly $52 million • Exelon was recognized for its commitment to diversity by Forbes, DiversityInc, Human Rights Campaign and the Military Times • Exelon’s total diverse supply spend exceeded $2.0B for the 3rd consecutive year • Exelon named to Dow Jones Sustainability North America Index for 14th year in a row (1) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture. Statistics represent full year 2019 results. 5 Q4 2019 Earnings Release Slides

Utility Investments Lead to Customer Benefits Over the last four years Exelon Utilities have invested $22 billion in resilience, reliability and infrastructure improvements and plan to invest $26 billion over the next four years. These investments have provided benefits to all of our 10 million utility customers: Improving Customer Service: Each utility had its best ever performance in the Customer Satisfaction Index in 2019 Keeping Electricity Affordable: Residential rates in Baltimore, Chicago, Philadelphia and Washington D.C are below the average for the 20 largest cities and the national average Enhancing Reliability: Frequency of outages has been reduced by 47% at ComEd and 22% at BGE since 2012. PHI has reduced frequency of outages by 30% since the merger. Duration of outages has been reduced by 52% at ComEd and 38% at BGE since 2012. Modernizing Gas Infrastructure: Over the last two years BGE and PECO have replaced more than 200 miles of outmoded cast iron and bare steel mains and nearly 30,000 metallic gas services 6 Q4 2019 Earnings Release Slides

7 Customer Benefits are Enabled Through Regulatory Models •Distribution System Investment Charge tracker provides a mechanism to begin recovering gas and electric infrastructure investments for reliability every six months Delaware •On May 30, 2019, Pepco DC filed first multi-year rate plan District of •DC PLUG provides for contemporaneous recovery of reliability and resiliency investments Columbia •Recovery through Formula Rate Plan since 2012 •Future Energy Jobs Act allows for recovery on energy efficiency programs Illinois •PC 51 allows multi-year rate plans for up to three years; The MDPSC’s Order on February 4, 2020 established a multi-year rate plan pilot and an associated framework •STRIDE program allows for contemporaneous recovery of the accelerated replacement of aging gas infrastructure Maryland •EmPOWER MD allows for recovery on energy efficiency programs •PowerAhead program allows for a capital tracker recovery mechanism for resiliency investments •Investment Infrastructure Program permits the recovery of certain levels of capital through a capital tracker recovery mechanism New Jersey •Fully projected future test year eliminates regulatory lag and better enables full cost recovery •DSIC recovery mechanism provides recovery for Long-term Infrastructure Improvement Plan for electric and gas distribution in between rate cases Pennsylvania •Act 58 of 2018 allows for alternative ratemaking including performance-based rates, multi-year rate plans, decoupling and formula rates 7 Q4 2019 Earnings Release Slides

8 Stakeholder Reaction to FERC PJM Capacity Market Order Illinois Maryland The Commission’s expanded MOPR will likely prevent many new [T]he December 2019 Order forcefully treads on states’ rights as they capacity resources with beneficial environmental attributes from pertain to state jurisdiction over both generation resources and clearing PJM’s capacity auctions. The December 19 Order forces environmental programs . . . As the only alternative presented in the states to either leave PJM’s capacity market or allow the Commission December 2019 Order, the Commission is effectively inviting states to and PJM to usurp the states’ FPA-protected role regarding capacity exit PJM’s capacity market. resources. -- Illinois Commerce Commission -- Maryland Public Service Commission [W]e are extremely concerned by the Federal Energy Regulatory Commission (FERC)’s unprecedented expansion of the Minimum Offer The ability of our state to retain some level of sovereignty over energy Price Rule (MOPR) and how this rash decision will impact PJM’s policy is paramount given the long-term challenges it must meet. The Capacity Market. Specifically, we believe this decision will have order runs counter to meeting those challenges and severely infringes crippling impacts on your consumers and our constituents, including on the right of states to independently determine and pursue unique dramatic increases in rates and threatening a burgeoning clean strategies or programs best suited for their citizens and communities. energy market. -- Members of Congress including Senator Tammy -- The Maryland Energy Administration Duckworth and Representative Cheri Bustos New Jersey Consumer Advocates Because most supply-side resources receiving state funding are low- The Order’s new MOPR regimen will disconnect the auction, and or zero-carbon resources, the Order effectively disregards state clean PJM’s RPM as a whole, from the region’s actual reliability needs and energy programs, and instead requires consumers to purchase from the foundational precept that resources should compete to reliability services exclusively from emitting resources. provide capacity on the basis of their net costs – those not covered by -- New Jersey Board of Public Utilities revenues received from any source for providing other products or services. And it will obligate millions of consumers in the PJM service Further, the state is proceeding with its march towards 100% clean area to buy far more capacity than they need, at enormous and energy in the face of federal energy regulators, including the U.S. unnecessary cost. -- DC Office of People’s Counsel, Maryland Office Department of Energy (U.S. DOE) and the Federal Energy Regulatory of People’s Counsel and New Jersey Division of Rate Counsel Commission (FERC), that are actively attempting to support fossil fuel interests in the PJM region under the guise of promoting “fair” The FERC ruling was structured specifically to penalize states such as competition or “resilience” planning. In order to meet the state’s Illinois that have made cost-saving investments in energy efficiency clean energy targets, consumers in New Jersey must be free to and renewable sources of power. But if we act now, we can take the choose a suite of generation resources that meet state policy goals. power back from Washington. -- David Kolata, Citizens Utility Board -- New Jersey Energy Master Plan and Clean Jobs Coalition Member 8 Q4 2019 Earnings Release Slides

Utility Operating Highlights At CEG Merger (2012) 2015 2019 Operations Metric BGE ComEd PECO PHI BGE ComEd PECO PHI OSHA Recordable Rate Electric 2.5 Beta SAIFI (Outage Operations Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Satisfaction N/A Customer Service Level % of Calls Operations Answered in <30 sec Abandon Rate Percent of Calls Responded to No Gas No Gas Gas Operations in <1 Hour Operations Operations Electric Utility Panel of 24 rd nd nd th Performance Overall Rank (1) 23 2 2 18 Utilities Quartiles • All utilities had their best-ever customer satisfaction scores • ComEd scored in the top decile for service level with ComEd, BGE and PECO achieving best on record performances • Reliability performance was mixed across the utilities: o ComEd recorded best ever results in SAIFI and CAIDI o PHI delivered best ever SAIFI performance • Top decile Gas odor response for the 7th consecutive year for BGE and PECO and 3rd consecutive year for PHI (1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer 9 Q4 2019 Earnings Release Slides

Best in Class at Generation and Constellation Generation Operational Metrics Constellation Metrics • Continued best in class performance across our Nuclear fleet:(1) 79% retail power 36% power new (2,3) customer renewal − Capacity factor of 95.7% was the highest customer win rate ever for Exelon (owned and operated units) rate − Generated 155 TWhs(2) of zero emitting nuclear power avoiding approximately 81 million metric tonnes of carbon dioxide 91% natural gas 23 month average customer power contract − Carbon emissions rate 4 times less than the retention rate term next cleanest generator − 2019 average refueling outage duration of 21 days, matching Exelon’s 2018 record Average customer Stable Retail duration of more • Strong performance across our Fossil and Margins than 6 years Renewable fleet: − Power Dispatch Match: 97.9% − Renewables Energy Capture: 96.3% Note: Statistics represent full year 2019 results (1) Excludes Salem (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) 2019 capacity factor includes Three Mile Island for the Exelon period of operation prior to planned retirement (January 1 to September 20, 2019) 10 Q4 2019 Earnings Release Slides

2019 Financial Results Q4 2019 EPS Results Full Year 2019 EPS Results • Adjusted (non-GAAP) operating earnings $3.22 drivers versus full year guidance of $0.83 $3.01 $0.79 $3.00 - $3.30: $1.31 $1.16 Exelon Utilities $0.41 $0.44 – Favorable weather $0.37 $0.37 – Lower costs from major storms – Higher distribution revenues $0.10 $0.10 $0.54 $0.55 – ComEd ROEs* $0.12 $0.12 $0.49 $0.52 $0.07 $0.07 Exelon Generation $0.15 $0.15 $0.71 $0.71 – Favorable O&M ($0.05) ($0.05) ($0.25) ($0.23) – Realization of R&D tax benefit Q4 GAAP Q4 Adjusted – NDT realized gains(1) Earnings Operating FY GAAP FY Adjusted Earnings Operating Earnings* – Lower portfolio optimization Earnings* – Outages at owned and ExGen PECO ComEd contracted assets BGE PHI HoldCo – Lower load volumes Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 11 Q4 2019 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q4 2019: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities PHI Utilities 10.0% $30.0/10.3% 8.0% $10.8/9.2% $40.8/10.0% ROE* (%)ROE* 6.0% Earned 4.0% 2.0% 0.0% $0 $5 $10 $15 $20 $25 $30 $35 $40 $45 $50 2019E Rate Base ($B) TTM ROEs* PHI Utilities Legacy Exelon Utilities Consolidated Exelon Utilities Q4 2019 9.2% 10.3% 10.0% Q4 2018(1) 8.3% 10.1% 9.6% Note: Represents the twelve-month period ending December 31, 2019 and December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Size of bubble based on rate base. (1) Q4 2018 TTM ROE* for PHI and Consolidated EU was changed from 8.4% and 9.7%, respectively, to 8.3% and 9.6%, respectively, to reflect the correction of an error at PHI 12 Q4 2019 Earnings Release Slides

Our Capital Plan Drives Leading Rate Base Growth Capital Expenditures ($M) Rate Base ($B)(1) 6,475 6,450 6,550 6,475 54.2 1,125 +7.3% 1,300 1,200 1,150 50.7 47.3 9.5 44.2 8.9 1,225 40.8 8.3 1,125 1,200 1,200 7.7 10.9 6.9 10.0 9.2 8.4 1,800 1,675 7.8 1,675 1,700 13.4 12.7 11.9 11.5 10.8 2,350 2,325 2,400 2,450 20.4 17.9 19.1 15.3 16.6 2020E 2021E 2022E 2023E 2019E 2020E 2021E 2022E 2023E BGE PECO PHI ComEd ~$26B of capital planned to be invested at Exelon utilities from 2020–2023 for grid modernization and resiliency for the benefit of our customers Note: CapEx numbers are rounded to nearest $25M and numbers may not sum due to rounding (1) Rate base reflects year-end estimates 13 Q4 2019 Earnings Release Slides

Exelon Utilities Project EPS* Growth of 6-8% to 2023 Exelon Utilities Operating Earnings* $2.60 $2.60 $2.50 $2.50 $2.40 $2.30 $2.25 $2.30 $2.20 $2.20 $2.10 $2.10 $2.05 $2.00 $1.91 $1.95 $1.90 $1.80 $1.80 Utility Adjusted Operating Operating Earnings* Adjusted Utility $1.75 $1.70 $0.00 2019A 2020E 2021E 2022E 2023E Rate base growth combined with positive regulatory outcomes drive EPS growth Note: Includes after-tax interest expense held at Corporate for debt associated with utility investment 14 Q4 2019 Earnings Release Slides

Exelon Generation: Gross Margin* Update Change from December 31, 2019 September 30, 2019 Gross Margin Category ($M)(1) 2020 2021 2020 2021 Open Gross Margin*(2) $3,600 $3,450 $(400) $(100) (including South, West, New England, Canada hedged gross margin) Capacity and ZEC Revenues(2) $1,900 $1,850 - - Mark-to-Market of Hedges(2,3) $850 $350 $450 $100 Power New Business / To Go $450 $750 $(50) - Non-Power Margins Executed $250 $150 - - Non-Power New Business / To Go $250 $350 - - Total Gross Margin*(4) $7,300 $6,900 - - Recent Developments • 2020 and 2021 Total Gross Margins* are flat due to declining power prices, offset by our hedges; executed $50M of power new business in 2020 • Behind ratable hedging position reflects our fundamental view of power prices ― ~6-9% behind ratable in 2020 when considering cross commodity hedges ― ~3-6% behind ratable in 2021 when considering cross commodity hedges (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 December 31, 2019 market conditions 15 Q4 2019 Earnings Release Slides

Driving Costs and Capital Out of the Generation Business Adjusted O&M* ($M) Capital Expenditures ($M)(1) 4,200 4,150 1,800 125 1,675 75 825 825 850 775 2020E 2021E 2020E 2021E Committed Growth Nuclear Fuel Base Continued focus on all O&M and capital costs at ExGen Note: All amounts rounded to the nearest $25M and numbers may not sum due to rounding (1) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments 16 Q4 2019 Earnings Release Slides

Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Exelon S&P FFO/Debt %*(1,2) ExGen Debt/EBITDA Ratio*(4) 25% 4.0 20% 19%-21% 20% 3.0x S&P Threshold 3.0 15% 2.4x 2.0 1.9x 10% Book Excluding Non-Recourse 5% 1.0 0% 0.0 2020 Target 2020 Target Credit Ratings by Operating Company Current Ratings(3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A2 A2 A2 S&P BBB BBB+ A A A A A A Fitch BBB+ BBB A A+ A A- A A- (1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment (2) Exelon Corp downgrade threshold (orange dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp (3) Current senior unsecured ratings as of December 31, 2019, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (4) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* 17 Q4 2019 Earnings Release Slides

2020 Adjusted Operating Earnings* Guidance $3.22(1) $3.00 - $3.30(2) Key Year-Over-Year Drivers • ExGen: Lower realized energy prices and capacity revenues and absence $1.31 of R&D tax benefit and NDT realized $1.20 - $1.30 gains • BGE: Higher depreciation, partially offset by higher distribution and transmission revenues $0.37 $0.30 - $0.40 • PECO: Higher depreciation and interest, partially offset by higher $0.55 transmission revenues $0.45 - $0.55 • PHI: Higher distribution and transmission revenues, partially $0.52 offset by higher depreciation $0.50 - $0.60 • ComEd: Increased capital investments to improve reliability in $0.71 distribution and transmission, offset $0.65 - $0.75 by impact of treasuries ($0.23) ($0.20) 2019 Actuals 2020 Guidance Expect Q1 2020 Adjusted Operating Earnings* of $0.85 - $0.95 per share Note: Amounts may not sum due to rounding (1) 2019 results based on 2019 average outstanding shares of 974M (2) 2020E earnings guidance based on expected average outstanding shares of 978M 18 Q4 2019 Earnings Release Slides

2020 Business Priorities and Commitments Maintain industry leading operational excellence Meet or exceed our financial commitments Effectively deploy ~$6.5B of utility capex Ensure timely recovery on investments to enable customer benefits Support Enactment of Clean Energy Policies Grow dividend at 5% rate Continued commitment to corporate responsibility 19 Q4 2019 Earnings Release Slides

The Exelon Value Proposition ▪ Regulated Utility Growth with utility EPS rising 6-8% annually from 2019- 2023 and rate base growth of 7.3%, representing an expanding majority of earnings ▪ ExGen’s free cash generation will support utility growth, ExGen debt reduction, and the external dividend ▪ Optimizing ExGen value by: • Seeking fair compensation for the zero-carbon attributes of our fleet; • Closing uneconomic plants; • Monetizing assets; and, • Maximizing the value of the fleet through our generation to load matching strategy ▪ Strong balance sheet is a priority with all businesses comfortably meeting investment grade credit metrics through the 2023 planning horizon ▪ Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 5% annual dividend growth through 2020(1); and, • Debt reduction (1) Quarterly dividends are subject to declaration by the board of directors 20 Q4 2019 Earnings Release Slides

Additional Disclosures 21 Q4 2019 Earnings Release Slides

Exelon Utilities Project EPS Growth of 6-8% to 2023 Q4 2018 Operating Earnings*(1) Q4 2019 Operating Earnings* $2.60 $2.60 $2.60 $2.50 $2.50 $2.45 $2.50 $2.40 $2.40 $2.30 $2.25 $2.30 $2.20 $2.15 $2.25 $2.30 $2.15 $2.10 $2.05 $2.20 $2.20 $2.00 $2.10 $2.10 $2.05 $1.90 $1.95 $1.80 $2.00 $1.80 $1.85 $1.95 $1.70 $1.73 $1.75 $1.90 $1.91 $1.60 $1.80 $1.80 $1.50 $1.75 $1.50 $1.70 $0.00 $0.00 2018A 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Utility growth rate remains 6-8%, driven by rate base growth and positive regulatory outcomes Note: Includes after-tax interest expense held at Corporate for debt associated with utility investment (1) 2018 Actuals were changed from $1.74 to $1.73 to reflect the correction of an error at PHI 22 Q4 2019 Earnings Release Slides

Utility Capex and Rate Base vs. Previous Disclosure Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 6,475 6,450 6,550 6,475 5,925 5,875 5,750 800 5,325 5,475 850 800 750 800 775 700 700 775 1,325 1,550 1,300 1,300 1,275 1,100 1,075 950 1,000 4,125 4,300 4,450 4,425 3,675 3,850 3,875 3,700 4,075 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +7.3% +7.8% 54.2 50.7 50.7 47.3 47.3 7.4 44.2 6.8 44.2 7.0 41.2 6.3 40.8 6.3 37.6 5.5 5.6 10.8 4.9 10.3 4.9 10.0 4.2 9.2 9.6 9.1 9.5 8.2 8.8 8.7 31.4 33.5 31.4 33.7 35.9 25.2 27.6 29.5 27.2 29.5 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Gas Delivery/Other(1) Electric Transmission Electric Distribution We plan to invest $25.9B of capital in utilities from 2020-2023, supporting rate base growth of 7.3% from 2019-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program 23 Q4 2019 Earnings Release Slides

Mechanisms Cover Bulk of Rate Base Growth Rate Base Growth Breakout 2020–2023 ($B) 3.5 13.4 Base Rate Case 1.0 Tracker/Formula Rate 2.5 4.6 3.4 1.2 2.2 3.1 1.0 2.1 8.7 3.4 1.3 2.1 2020E 2021E 2022E 2023E Total Of the ~$13.4B of rate base growth Exelon Utilities forecasts over the next 4 years, ~65% will be recovered through existing formula and tracker mechanisms Note: Numbers may not sum due to rounding 24 Q4 2019 Earnings Release Slides

ComEd Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 2,450 2,425 2,350 2,325 2,400 2,150 2,175 425 500 1,900 475 500 450 1,875 450 325 300 325 1,875 2,000 1,900 1,825 1,950 1,950 1,575 1,725 1,575 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +7.8% +7.5% 19.2 19.1 20.4 16.7 18.0 16.6 17.9 1.1 14.2 15.6 1.1 15.3 1.0 0.8 1.0 4.0 0.7 0.9 4.2 4.6 0.4 0.6 3.8 4.0 0.6 3.8 4.0 3.5 3.7 3.7 14.1 13.8 14.7 10.3 11.3 12.1 13.0 11.0 12.0 12.9 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Other(1) Electric Transmission Electric Distribution Project ~$9.5B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program 25 Q4 2019 Earnings Release Slides

PECO Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 1,200 1,225 1,200 1,125 975 1,000 975 975 1,000 300 275 250 275 250 125 75 250 300 300 250 200 100 125 125 125 50 50 825 875 600 575 600 650 650 700 700 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +8.5% +8.2% 10.9 10.0 9.7 9.2 9.1 2.7 7.9 8.4 7.8 8.4 2.6 7.1 2.5 2.1 2.3 2.1 2.4 1.3 1.9 1.1 1.9 1.2 1.7 1.1 1.1 1.0 1.1 1.0 1.0 1.0 6.0 6.3 6.9 4.4 5.0 5.3 5.6 4.9 5.3 5.7 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Gas Delivery Electric Transmission Electric Distribution Project ~$4.8B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 26 Q4 2019 Earnings Release Slides

BGE Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 1,300 1,250 1,175 1,200 1,100 1,125 1,150 1,075 475 450 950 400 450 450 425 400 425 375 275 275 225 200 300 200 250 225 175 575 475 525 400 400 525 500 500 475 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +8.2% +8.3% 9.5 8.7 8.3 8.9 7.7 8.1 7.7 6.9 6.9 3.0 6.3 2.7 2.8 2.3 2.5 2.3 2.5 2.0 2.0 1.7 1.6 1.8 1.4 1.5 1.7 1.4 1.5 1.1 1.3 1.2 4.7 3.4 3.7 4.0 4.1 4.3 3.7 4.0 4.3 4.5 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Gas Delivery Electric Transmission Electric Distribution Project ~$4.8B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 27 Q4 2019 Earnings Release Slides

PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 1,800 1,675 1,700 1,675 1,525 1,550 1,550 75 1,425 100 75 75 1,375 75 75 50 75 550 50 425 450 550 450 300 425 475 375 1,175 1,025 1,025 1,000 1,075 975 1,125 1,050 1,150 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +5.7% +7.0% 13.4 13.1 12.7 12.1 11.5 11.9 0.6 10.8 11.4 0.5 10.8 0.6 10.0 0.5 0.4 0.5 3.1 0.4 0.4 3.4 0.4 2.9 3.0 0.3 2.9 3.0 2.8 2.9 2.6 2.8 9.2 8.5 9.1 9.7 7.1 7.6 8.1 8.7 7.6 8.2 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Gas Delivery Electric Transmission Electric Distribution Project ~$6.9B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 28 Q4 2019 Earnings Release Slides

ACE Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 350 375 350 350 300 325 325 300 175 150 150 150 250 125 150 150 125 100 200 200 225 225 200 175 175 150 175 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +7.7% +5.5% 3.0 3.1 2.9 2.8 2.8 2.5 2.6 2.5 2.6 2.3 1.0 1.1 1.1 1.0 1.0 1.0 1.1 0.8 0.9 0.9 1.9 2.0 1.5 1.6 1.7 1.8 1.6 1.7 1.8 1.8 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Electric Transmission Electric Distribution Project ~$1.4B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 29 Q4 2019 Earnings Release Slides

Delmarva Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 450 375 400 100 375 350 75 325 350 375 75 325 75 50 50 75 75 75 125 100 100 125 100 100 75 100 100 225 225 200 200 175 200 175 175 200 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +3.9% +4.4% 3.5 3.6 3.3 3.5 3.3 3.4 3.1 3.2 3.1 0.6 0.6 2.9 0.5 0.5 0.4 0.5 0.4 0.4 0.4 0.3 1.0 1.0 1.0 1.0 1.0 1.0 1.0 0.9 1.0 1.0 1.8 1.9 1.9 2.0 1.6 1.7 1.8 1.9 1.9 1.7 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Gas Delivery Electric Transmission Electric Distribution Project ~$1.6B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 30 Q4 2019 Earnings Release Slides

Pepco Capital Expenditure and Rate Base Forecast Q4 2018 Capital Expenditures ($M) Q4 2019 Capital Expenditures ($M) 1,100 950 975 975 900 875 325 800 225 725 700 325 225 175 250 175 75 100 750 775 725 650 625 625 600 675 650 2019E 2020E 2021E 2022E 2019A 2020E 2021E 2022E 2023E Q4 2018 Rate Base ($B) Q4 2019 Rate Base ($B) +8.1% +6.8% 6.6 6.3 6.7 5.9 5.6 5.7 1.0 5.3 5.6 1.2 5.2 0.9 4.9 0.9 0.9 0.9 0.9 0.9 0.9 0.9 5.7 5.0 5.4 4.8 5.4 4.0 4.3 4.6 4.3 4.7 2018E 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E 2023E Electric Transmission Electric Distribution Project ~$3.9B of Capital being invested from 2020-2023 Note: Numbers rounded to nearest $25M and may not sum due to rounding. Rate base reflects year-end estimates. 31 Q4 2019 Earnings Release Slides

ExGen O&M and Capex vs. Previous Disclosure Adjusted O&M* - Q4 2018 ($M) Adjusted O&M* - Q4 2019 ($M) 4,325 4,250 4,200 4,200 4,150 2019E 2020E 2021E 2020E 2021E CapEx – Q4 2018 ($M)(1) CapEx – Q4 2019 ($M)(1) 1,900 1,925 1,800 150 1,750 1,675 200 125 150 75 900 900 775 825 825 875 825 825 850 775 2019E 2020E 2021E 2020E 2021E Committed Growth Nuclear Fuel Base Note: All amounts rounded to the nearest $25M and numbers may not sum due to rounding (1) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments 32 Q4 2019 Earnings Release Slides

Adjusted O&M* Forecast ($ in millions) 7,850 $7,925 $750 $775 $775 $825 Key Year-over-Year Drivers $1,000 $1,000 • BGE: Increase driven by inflation • PECO: Increase driven by return to normal storm and inflation $1,275 $1,300 • PHI: Driven by inflation, substation costs and cyber security costs, offset by cost management initiatives • ComEd: Increase driven by inflation • ExGen: Additional nuclear outages and lower NEIL distribution, partially offset by cost management initiative and nuclear $4,175 retirement $4,200 -$100 -$175 2019 Actuals(1) BGE PHI ExGen 2020 Guidance(1) PECO ComEd HoldCo (1) All amounts rounded to the nearest $25M and may not sum due to rounding 33 Q4 2019 Earnings Release Slides

2020 Projected Sources and Uses of Cash Total Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(9) Exelon Utilities Balance (1) All amounts rounded to the nearest $25M. Figures may not add due to Beginning Cash Balance*(2) 1,500 rounding. (2) Adjusted Cash Flow from Operations 825 1,500 825 1,150 4,275 3,750 (150) 7,900 (2) Gross of posted counterparty Base CapEx and Nuclear Fuel(3) - - - - - (1,675) (100) (1,775) collateral Free Cash Flow* 825 1,500 825 1,150 4,275 2,075 (250) 6,100 (3) Figures reflect cash CapEx and Debt Issuances 300 1,000 350 500 2,150 975 900 4,025 CENG fleet at 100% Debt Retirements - (500) - - (500) (2,500) (900) (3,900) (4) Anticipated proceeds from Project Financing - - - - - (75) - (75) securitization of Constellation Equity Issuance/Share Buyback - - - - - - - - Accounts Receivable Portfolio AR Securitization (4) - - - - - 750 - 750 (5) Other Financing primarily includes Contribution from Parent 325 500 225 325 1,350 - (1,350) - expected changes in commercial (5) paper, tax sharing from the parent, Other Financing 150 300 75 (25) 500 325 (250) 600 renewable JV distributions, tax Financing*(6) 775 1,300 650 775 3,500 (525) (1,575) 1,400 equity cash flows and debt issue Total Free Cash Flow and Financing 1,575 2,800 1,475 1,925 7,775 1,550 (1,825) 7,500 costs Utility Investment (1,300) (2,350) (1,125) (1,675) (6,475) - - (6,475) (6) Financing cash flow excludes ExGen Growth(3,7) - - - - - (125) - (125) intercompany dividends Acquisitions and Divestitures - - - - - - - - (7) ExGen Growth CapEx primarily Equity Investments - - - - - (25) - (25) includes Retail Solar and W. Dividend(8) - - - - - - - (1,500) Medway Other CapEx and Dividend (1,300) (2,350) (1,125) (1,675) (6,475) (125) - (8,075) (8) Dividends are subject to declaration Total Cash Flow 275 425 350 250 1,325 1,425 (1,825) (575) by the Board of Directors Ending Cash Balance*(2) 925 (9) Includes cash flow activity from Holding Company, eliminations and other corporate entities Consistent and reliable free cash flows Supported by a strong balance sheet Enable growth & value creation Operational excellence and financial Strong balance sheet enables flexibility to Creating value for customers, discipline drives free cash flow* reliability raise and deploy capital for growth communities and shareholders ✓ Generating $6.1B of free cash flow*, ✓ $1.7B of long-term debt at the utilities, net ✓ Investing $6.6B of growth CapEx, with including $2.1B at ExGen and $4.3B at the of refinancing, to support continued growth $6.5B at the Utilities and $0.1B at ExGen Utilities and $1.5B of ExGen long-term debt reduction Note: Numbers may not sum due to rounding 34 Q4 2019 Earnings Release Slides

Exelon Debt Maturity Profile(1) As of 12/31/19 (2) ($M) LT Debt Balances (as of 12/31/19) BGE 3.3B 500 ComEd 8.7B PECO 3.6B PHI 6.6B ExGen recourse(3) 6.0B ExGen non-recourse 2.0B HoldCo 6.3B Consolidated 36.4B 910 2,512 1,023 1,225 1,200 850 500 600 2,150 1,189 175 1,550 1,430 1,400 1,275 1,150 997 900 850 900 833 807 750 763 833 788 750 185 675 700 650 741 360 300 303 258 295 350 78 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon’s weighted average LTD maturity is approximately 15 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 Q4 2019 10-K GAAP financials, which include items listed in footnote 1 (3) Includes legacy CEG debt of $550M and $258M in 2020 and 2032; and tax-exempt bonds of $412M in 2020 35 Q4 2019 Earnings Release Slides

EPS Sensitivities* 2020E 2021E Henry Hub Natural Gas + $1/MMBtu $0.09 $0.31 (1) - $1/MMBtu ($0.08) ($0.29) NiHub ATC Energy Price + $5/MWh $0.01 $0.13 - $5/MWh ($0.01) ($0.13) ExGen EPS Impact*EPS ExGen PJM-W ATC Energy Price + $5/MWh ($0.00) $0.05 - $5/MWh $0.00 ($0.06) ComEd Distribution ROE $0.03 $0.03 Pension Expense $0.00 $0.02 InterestRate Cost of Debt ($0.02) ($0.02) Sensitivity to+50 Sensitivity BP Share count (millions) 978 981 Exelon Consolidated Effective Tax Rate 16% 17% ExGen Effective Tax Rate 20% 23% Exelon Consolidated Cash Tax Rate 0% (4%) (1) Based on December 31, 2019, 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 EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are also considered. ExGen EPS sensitivities assume a marginal tax rate of 25.5%. 36 Q4 2019 Earnings Release Slides

Historical Nuclear Capital Investment Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Baseline CAGR Cancelled Growth Fukushima Growth(4) Nuclear Baseline (excluding Fuel) (2,3) 975 -2.3% 925 50 825 850 150 775 250 25 175 650 25 675 175 175 50 25 25 600 575 50 100 75 525 650 700 675 575 575 600 550 600 575 525 2012 2013 2014 2015 2016 2017 2018 2019 2020E 2021E (5,6) Nuclear Capacity Factor Significant historical investments have mitigated Industry Average Exelon asset management issues and prepared sites for 95.7% license extensions already received, reducing 94.1% 94.3% 94.6% 94.1% 94.6% 92.7% 93.7% future capital needs. In addition, internal cost initiatives have found more cost efficient solutions to large CapEx spend, such as 89.3% 89.2% 90.0% 90.0% 89.2% 89.3% leveraging reverse engineering replacements 84.6% rather than large system wide modifications, resulting in baseline CAGR of -2.3%. 2012 2013 2014 2015 2016 2017 2018 2019 (1) Reflects accrual capital expenditures with CENG at 50% ownership. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Reflects Exelon ownership share. Includes CENG beginning in April 2014, FitzPatrick beginning in April of 2017, and Oyster Creek and TMI partial year operation in 2018 and 2019, respectively. Excludes Salem and Fort Calhoun. (6) Industry average is for major operators excluding Exelon and includes 3 months of Fitzpatrick prior to Exelon acquisition. 2019 industry average (excluding Exelon) was not available at the time of publication. 37 Q4 2019 Earnings Release Slides

Exelon Recognition and Partnerships SUSTAINABILITYSustainability DIVERSITYDiversity& INCLUSION and Inclusion Dow Jones Sustainability North America Index HeForShe Exelon named to Dow Jones Sustainability North America Index for the Exelon is a Thematic Champion in the United Nations HeForShe 14th consecutive year in recognition of the Corporation’s leading movement, which focuses on engaging men and boys in the environmental, social and economic sustainability performance among achievement of global gender equality. Exelon has committed to invest North American utility companies. $3 million to STEM education for young women and to reach retention Energy Star® Partner of the Year: Sustained Excellence parity among men and women by year end 2020. In 2019, Exelon Utilities BGE, ComEd, Delmarva, PECO and Pepco Billion Dollar Roundtable received the Partner of the Year: Sustained Excellence award from U.S. For the third consecutive year, Exelon maintained its status as a EPA in recognition of their continuing leadership efforts in customer member of the Billion Dollar Roundtable, an organization that promotes energy efficiency programs supplier diversity for corporations achieving $1 billion or more in annual CDP Disclosure direct spending with minority and women-owned businesses. Exelon has been a strong performer in the CDP Climate Change and CEO Action for Diversity & Inclusion Water disclosure surveys for the last ten years. Exelon joined the CEO Action for Diversity & Inclusion™ , the largest Wildlife Habitat Council’s Employee Engagement Award CEO-driven business commitment to advance diversity and inclusion Exelon was recognized for its broad-based engagement with employee within the work place in order to cultivate a workplace where diverse teams around habitat and conservation education activities. perspectives and experiences are welcomed and respected. Community Engagement Workforce $51.5 million DiversityInc Top 50 Companies 2019 Last year, Exelon and its employees committed approximately $51.5 Exelon ranked No. 24 on DiversityInc's list of Top 50 companies for million to non-profit organizations and volunteered a record-setting diversity, 4th of Top 10 companies for diverse leadership and 10th for 250,790 hours. the top 17 companies in hiring for veterans. United Way of Whiteside County “Live United Award” Fortune Magazine “World’s Most Admired Companies” 2019 Exelon received this recognition for its consistent exhibition of For the twelfth time, Exelon was named to Fortune Magazine’s list for leadership throughout the community, including support for the United its high marks among Forbes’ financial soundness, innovation and Way in both Whiteside County and around the United States. quality of management criteria. Human Rights Campaign “Best Places to Work” 2011-2020 United Way of Metropolitan Chicago “Corporate Leadership Award” Exelon earned the designation of “Best Place to Work” on HRC’s Exelon was recognized for its commitment to the community and Corporate Equality Index for the ninth consecutive year in 2020, partnership with United Way and its partner agencies. receiving a perfect score of 100. Girl Scouts of Greater Chicago and Northwest Indiana ”Corporate The Military Times Best for Vets 2013-2019 Appreciation Award” For the seventh year in a row, Exelon received this recognition for its Exelon has supported this organization for over 25 years, including its commitment to providing opportunities to America's veterans. STEM and Robotics programs. This award honors corporations who Forbes America’s Best Employers For Diversity 2018-2020 have made the world a better place by advancing opportunities for For the third consecutive year, Forbes recognized Exelon for its girls and women. diversity within executive ranks, diversity as a business imperative and proactive communication on the issue. Exelon ranked 199th among the top 500 employers across all industries in the U.S. 38 Q4 2019 Earnings Release Slides

Exelon Utilities 39 Q4 2019 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep ROE / Requirement Order Equity Ratio 8.91% / (1,2) ComEd FO ($16.9M) 47.97% Dec 4, 2019 Elec: 9.70%; (1,4) BGE RT SA FO $79.0M Gas: 9.75% / Dec 17, 2019 (3) N/A (1,5) 10.30% / Pepco DC $160.0M IT RT EH IB RB 50.68% Q4 2020 Electric 3-Year MYP 10.30% / DPL MD (1) CF IT RT EH IB FO $18.5M 50.53% Jul 2, 2020 Electric CF Rate case filed RT Rebuttal testimony IB Initial briefs FO Final commission order IT Intervenor direct testimony EH Evidentiary hearings RB Reply briefs SA Settlement agreement Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission, Maryland Public Service Commission, Pennsylvania Public Utility Commission, Delaware Public Service Commission, Public Service Commission of the District of Columbia, and New Jersey Board of Public Utilities 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 in initial filing was a decrease of ($6.4M). Through the discovery period in the current proceeding, ComEd agreed to ~($10.5M) in adjustments to limit issues in the case. (3) Rate of Return and Return on Equity are used solely for AFUDC, surcharges and regulatory asset carrying charges and sets no precedent (4) Approved revenue requirement reflects $25.0M increase for electric and $54.0M increase for gas. Increase reflects $7.1M of ERI (electric) and $8.7M of STRIDE (gas) that will be transferred from the ERI and STRIDE surcharges to base rates. (5) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $84M, $40M and $36M with rates effective November 1, 2020, January 1, 2021 and January 1, 2022, respectively. 40 Q4 2019 Earnings Release Slides

ComEd Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 19-0387 • April 8, 2019, ComEd filed its annual distribution formula rate update with the Illinois Test Year January 1, 2018 – December 31, 2018 Commerce Commission seeking a decrease to Test Period 2018 Actual Costs + 2019 Projected Plant distribution base rates Additions • October 23, 2019, ComEd received the ALJ proposed order. No additional adjustments to Common Equity Ratio 47.97% the revenue requirement were recommended. Rate of Return ROE: 8.91%; ROR: 6.51% • December 4, 2019, the Commission issued a Final Order in this case approving the requested Rate Base (Adjusted) $11,355M revenue requirement with no disallowances Revenue Requirement Decrease ($16.9M)(1,2) Residential Total Bill % Decrease (0.7%) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 4/8/2019 Intervenor testimony 6/20/2019 Rebuttal testimony 7/17/2019 Evidentiary hearings 8/29/2019 Initial briefs 9/12/2019 Reply briefs 9/26/2019 Commission order 12/4/2019 (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 a decrease of ($6.4M). Through the discovery period in the current proceeding, ComEd agreed to ~($10.5M) in adjustments to limit issues in the case. 41 Q4 2019 Earnings Release Slides

BGE Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. Case No. 9610 • Case originally filed on May 24, 2019 seeking an increase in electric and gas distribution revenues Test Year August 1, 2018 – July 31, 2019 • October 25, 2019, BGE filed a settlement agreement with the MDPSC. The black box Test Period 8 months actual + 4 months estimated agreement does not stipulate the ROE, ROR, Capital Common Equity Ratio N/A structure or Rate Base used to determine the agreed upon revenue increases. Rate of Return(2) Electric [ROE: 9.70%; ROR: 6.94%] • December 17, 2019, the Commission issued a Final Gas [ROE: 9.75%; ROR: 6.97%] Order in this case approving BGE’s proposed Settlement Agreement Rate Base (Adjusted) N/A Revenue Requirement Increase $79.0M(1,3) Residential Total Bill % Increase ~2.9%(4) Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Filed rate case 5/24/2019 Intervenor testimony 9/10/2019 Rebuttal testimony 10/4/2019 Settlement Agreement 10/25/2019 Commission order 12/17/2019 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Rate of Return and Return on Equity are used solely for AFUDC, surcharges and regulatory asset carrying charges and sets no precedent (3) Approved revenue requirement reflects $25.0M increase for electric and $54.0M increase for gas. Increase reflects $7.1M of ERI (electric) and $8.7M of STRIDE (gas) that will be transferred from the ERI and STRIDE surcharges to base rates. (4) Increase expressed as a percentage of a combined electric and gas residential customer total bill 42 Q4 2019 Earnings Release Slides

Pepco DC (Electric) Distribution Rate Case Filing 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 Test Year January 1 – December 31 Service Commission of the District of Columbia Test Period 2020, 2021, 2022 (DCPSC) seeking an increase in electric distribution base rates Proposed Common Equity Ratio 50.68% • Size of ask is driven by continued investments in electric distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.69% increase reliability and customer service 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B • MYP proposes five Performance Incentive (1,2) Mechanisms (PIMs) focused on system 2020-2022 Requested Revenue Requirement Increase $84M, $40M, $36M reliability, customer service and interconnection (2) 2020-2022 Residential Total Bill % Increase 7.0%, 4.2%, 3.7% Distributed Energy Resources (DER) Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 5/30/2019 Intervenor testimony 3/6/2020 Rebuttal testimony 4/8/2020 Evidentiary hearings 6/29/2020 - 7/3/2020 Initial briefs 8/26/2020 Reply briefs 9/10/2020 Commission order expected Q4 2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Company proposed incremental revenue requirement increases with rates effective November 1, 2020, January 1, 2021 and January 1, 2022, respectively 43 Q4 2019 Earnings Release Slides

Delmarva MD (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Case No. 9630 • December 5, 2019, Delmarva Power filed an application with the Maryland Public Service Test Year September 1, 2018 – August 31, 2019 Commission (MDPSC) seeking an increase in Test Period 12 months actual electric distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 50.53% in electric distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.19% increase reliability and customer service Proposed Rate Base (Adjusted) $858.0M Requested Revenue Requirement Increase $18.5M(1) Residential Total Bill % Increase 3.6% Detailed Rate Case Schedule Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Filed rate case 12/5/2019 Intervenor testimony 2/21/2020 Rebuttal testimony 3/20/2020 Evidentiary hearings 4/13/2020 - 4/17/2020 Initial briefs 5/8/2020 Commission order expected 7/2/2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings 44 Q4 2019 Earnings Release Slides

Exelon Generation Disclosures December 31, 2019 45 Q4 2019 Earnings Release Slides

Portfolio Management Strategy Align Hedging & Financials Portfolio Management Over Time Exercising Market Views Establishing Minimum Hedge Targets % Hedged High End of Profit Low End of Profit Purely ratable Capital Credit Rating Structure Actual hedge % % Hedged % Capital & Market views on timing, product Operating Dividend allocation and regional spreads Expenditure Open Generation Portfolio Management & reflected in actual hedge % with LT Contracts Optimization Protect Balance Sheet Ensure Earnings Stability Create Value 46 Q4 2019 Earnings Release Slides

Components of Gross Margin* Categories Gross margin* from Gross margin* linked to power production and sales other business activities Open Gross Capacity and ZEC MtM of “Power” New “Non Power” “Non Power” Margin* Revenues Hedges(2) Business Executed New Business •Generation Gross •Expected capacity •Mark-to-Market •Retail, Wholesale •Retail, Wholesale •Retail, Wholesale Margin* at current revenues for (MtM) of power, planned electric executed gas sales planned gas sales market prices, generation of capacity and sales •Energy •Energy including ancillary electricity ancillary hedges, •Portfolio Efficiency(4) Efficiency(4) revenues, nuclear •Expected including cross Management new •BGE Home(4) •BGE Home(4) fuel amortization commodity, retail revenues from business •Distributed Solar •Distributed Solar and fuels expense Zero Emissions and wholesale •Mid marketing •Portfolio •Power Purchase Credits (ZEC) load transactions new business Management / Agreement (PPA) •Provided directly origination fuels Costs and at a consolidated new business Revenues level for four major •Proprietary •Provided at a regions. Provided trading(3) consolidated level indirectly for each for all regions of the four major (includes hedged regions via gross margin* for Effective Realized South, West, New Energy Price England and (EREP), reference Canada(1)) price, hedge %, expected generation. Margins move from new business to Margins move from “Non power new MtM of hedges over the course of the business” to “Non power executed” over year as sales are executed(5) the course of the year (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* 47 Q4 2019 Earnings Release Slides

ExGen Disclosures December 31, 2019 Gross Margin Category ($M)(1) 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)(2) $3,600 $3,450 Capacity and ZEC Revenues(2) $1,900 $1,850 Mark-to-Market of Hedges(2,3) $850 $350 Power New Business / To Go $450 $750 Non-Power Margins Executed $250 $150 Non-Power New Business / To Go $250 $350 Total Gross Margin*(4) $7,300 $6,900 Reference Prices(4) 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.28 $2.42 Midwest: NiHub ATC prices ($/MWh) $22.45 $22.68 Mid-Atlantic: PJM-W ATC prices ($/MWh) $26.18 $27.45 ERCOT-N ATC Spark Spread ($/MWh) $14.07 $9.83 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $24.86 $27.27 (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 December 31, 2019 market conditions 48 Q4 2019 Earnings Release Slides

ExGen Disclosures December 31, 2019 Generation and Hedges 2020 2021 Exp. Gen (GWh)(1) 186,100 181,500 Midwest 96,600 95,500 Mid-Atlantic(2) 47,500 48,000 ERCOT 26,300 21,400 New York(2) 15,700 16,600 % of Expected Generation Hedged(3) 91%-94% 61%-64% Midwest 92%-95% 62%-65% Mid-Atlantic(2) 99%-102% 67%-70% ERCOT 81%-84% 52%-55% New York(2) 78%-81% 50%-53% Effective Realized Energy Price ($/MWh)(4) Midwest $27.50 $26.50 Mid-Atlantic(2) $36.50 $31.50 ERCOT(5) $5.00 $7.50 New York(2) $33.00 $27.50 (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 14 refueling outages in 2020 and 13 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.0% and 94.2% in 2020 and 2021, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2020 and 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (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) Spark spreads shown for ERCOT 49 Q4 2019 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities Gross Margin* Sensitivities (with existing hedges)(1) 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $115 $405 - $1/MMBtu $(110) $(380) NiHub ATC Energy Price + $5/MWh $15 $165 - $5/MWh $(15) $(165) PJM-W ATC Energy Price + $5/MWh $(5) $60 - $5/MWh $5 $(75) NYPP Zone A ATC Energy Price + $5/MWh $10 $40 - $5/MWh $(20) $(40) Nuclear Capacity Factor +/- 1% +/- $25 +/- $30 (1) Based on December 31, 2019 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 50 Q4 2019 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) 8,000 $7,450 7,500 $7,300 7,000 $7,100 6,500 $6,550 6,000 5,500 5,000 Approximate Gross ($ Margin* million) Gross Approximate 4,500 4,000 2020 2021 (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* ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin* in 2020 and 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of December 31, 2019. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. 51 Q4 2019 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2021 Total Gross Margin* South, Row Item Midwest Mid-Atlantic ERCOT New York West, NE & Canada (A) Start with fleet-wide open gross margin $3.45 billion (B) Capacity and ZEC $1.85 billion (C) Expected Generation (TWh) 95.5 48.0 21.4 16.6 (D) Hedge % (assuming mid-point of range) 63.5% 68.5% 53.5% 51.5% (E=C*D) Hedged Volume (TWh) 60.6 32.9 11.4 8.5 (F) Effective Realized Energy Price ($/MWh) $26.50 $31.50 $7.50 $27.50 (G) Reference Price ($/MWh) $22.68 $27.45 $9.83 $27.27 (H=F-G) Difference ($/MWh) $3.82 $4.05 ($2.33) $0.23 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $230 $135 ($25) $0 (J=A+B+I) Hedged Gross Margin ($ million) $5,650 (K) Power New Business / To Go ($ million) $750 (L) Non-Power Margins Executed ($ million) $150 (M) Non-Power New Business / To Go ($ million) $350 (N=J+K+L+M) Total Gross Margin* $6,900 million (1) Mark-to-market rounded to the nearest $5M 52 Q4 2019 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,675 $7,325 Other Revenues(4) $(150) $(150) Direct cost of sales incurred to generate revenues for certain $(225) $(275) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,300 $6,900 Key ExGen Modeling Inputs (in $M)(1,5) 2020 Other(6) $125 Adjusted O&M*(7) $(4,200) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization*(9) $(1,025) Interest Expense $(325) Effective Tax Rate 20.0% (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) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in ExGen Renewables JV (7) 2020 and 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) 2020 and 2021 TOTI excludes gross receipts tax of $125M (9) 2021 Depreciation & Amortization is unfavorable to 2020 by ($50M) 53 Q4 2019 Earnings Release Slides

2019A Earnings Waterfalls 54 Q4 2019 Earnings Release Slides

Q4 2019 QTD Adjusted Operating Earnings* Waterfall $0.03 R&D Tax Benefit(3) $0.01 Distribution and ($0.01) Other Transmission Rate Increases ($0.01) Other $0.83 $0.02 $0.02 Distribution Rate Increase ($0.01) Weather & Load ($0.01) Increased Storm Costs $0.21 ($0.01) Other $0.58 $0.00 $0.00 ($0.01) $0.03 $0.10 Market and Portfolio Conditions(1) $0.01 Distribution Rate $0.09 Lower Operating and Maintenance Increase Expense (2) $0.02 Other $0.08 R&D Tax Benefit(3) $0.05 Nuclear Outages(4) $0.03 Zero Emission Credit Revenue(5) ($0.12) Capacity Pricing ($0.02) Other 2018 ComEd PECO BGE PHI ExGen Corp 2019 Note: Amounts may not sum due to rounding (1) Primarily reflects higher realized energy prices (2) Includes a nuclear insurance credit, the impacts of previous cost management programs and lower pension and OPEB costs (3) Reflects the benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 – 2018 tax years (4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2019, including Salem (5) Primarily reflects an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019 55 Q4 2019 Earnings Release Slides

Q4 2019 YTD Adjusted Operating Earnings* Waterfall ($0.03) Income Taxes $0.09 Distribution Rate Increase $0.11 Distribution and ($0.01) Interest Expense ($0.01) Transmission Revenues Transmission Rate Increases $0.03 R&D Tax Benefit(5) (1) $0.02 Decreased Storm Costs ($0.01) Unfavorable Weather ($0.04) Other ($0.03) Unfavorable Weather and Load ($0.08) $3.22 $3.12 $0.04 $0.10 ($0.05) $0.02 $0.07 $0.05 Distribution Rate Increase $0.01 Distribution and Energy $0.02 Decreased Storm Costs(1) Efficiency Investment ($0.01) Interest Expense $0.01 Transmission Revenues ($0.02) Other ($0.27) Market and Portfolio Conditions(2) ($0.22) Capacity Pricing $0.20 Lower Operating and Maintenance Expense(3) $0.10 Nuclear Outages(4) $0.08 R&D Tax Benefit(5) $0.03 Other 2018 ComEd PECO BGE PHI ExGen Corp 2019 Note: Amounts may not sum due to rounding (1) Primarily reflects the absence of the March 2018 winter storms (2) Primarily reflects lower realized energy prices (3) Includes higher nuclear insurance credits, the impacts of previous cost managements programs and lower pension and OPEB costs (4) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2019, excluding Salem, partially offset by the impacts of higher nuclear outage days at Salem in 2019 (5) Reflects the benefits related to certain research and development activities that qualify for federal and state tax incentives for the 2010 – 2018 tax years 56 Q4 2019 Earnings Release Slides

2020E Earnings Waterfalls 57 Q4 2019 Earnings Release Slides

ComEd Adjusted Operating EPS* Bridge 2019 to 2020 ($0.02) $0.12 ($0.06) ($0.01) Inflation $0.71 ($0.01) Other ($0.05) $0.65 - $0.75 ($0.03) Energy Efficiency Amortization $0.09 Distribution & Transmission ($0.03) D&A $0.04 Energy Efficiency ($0.03) Treasury Yield Impact ($0.02) Interest Expense $0.02 Other ($0.03) Other 2019A(3) RNF(1) O&M(2) D&A Other 2020E(3,4) Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range (1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020 (4) Guidance assumes an effective tax rate for 2020 of 18.9% 58 Q4 2019 Earnings Release Slides

PECO Adjusted Operating EPS* Bridge 2019 to 2020 $0.55 $0.01 ($0.03) ($0.02) $0.45 - $0.55 ($0.01) $0.02 Transmission and ($0.01) Storms Distribution Revenues/Other ($0.01) Inflation ($0.01) Normalized Weather ($0.01) Other 2019A(3) RNF(1) O&M(2) D&A Other 2020E(3,4) Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range (1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020 (4) Guidance assumes an effective tax rate for 2020 of 10.6% 59 Q4 2019 Earnings Release Slides

BGE Adjusted Operating EPS* Bridge 2019 to 2020 ($0.02) $0.07 ($0.03) $0.37 ($0.01) Inflation ($0.01) Other ($0.04) $0.30 - $0.40 $0.05 Distribution $0.02 Transmission ($0.02) Taxes ($0.01) Interest Expense ($0.01) Other 2019A(3) RNF(1) O&M(2) D&A Other 2020E(3,4) Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range (1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020 (4) Guidance assumes an effective tax rate for 2020 of 19.3% 60 Q4 2019 Earnings Release Slides

PHI Adjusted Operating EPS* Bridge 2019 to 2020 ($0.01) $0.50 - $0.60 ($0.04) $0.07 $0.01 $0.52 $0.04 Distribution $0.03 Transmission 2019A(3) RNF(1) O&M(2) D&A Other 2020E(3,4) Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range (1) Revenue net fuel (RNF)* is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020 (4) Guidance assumes an effective tax rate for 2020 of 10.0% 61 Q4 2019 Earnings Release Slides

ExGen Adjusted Operating EPS* Bridge 2019 to 2020 ($0.07) Nuclear Outages ($0.03) NEIL distribution ($0.05) NDT Realized Gains $0.08 Nuclear Retirements $0.03 Other $1.31 ($0.04) $1.20 - $1.30 ($0.02) $0.02 ($0.02) ($0.14) Capacity Revenues ($0.10) Nuclear Retirements $0.03 Nuclear Retirements $0.20 Market Conditions ($0.01) Base Capex Depreciation 2019A(1) Gross Margin O&M D&A Other 2020E(1,2) Note: Drivers add up to mid-point of 2020 adjusted operating EPS* range (1) Shares Outstanding (diluted) are 974M in 2019 and 978M in 2020 (2) Guidance assumes a marginal tax rate of 25.5% for 2020 62 Q4 2019 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 63 Q4 2019 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation Three Months Ended December 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.15 $0.12 $0.10 $0.07 $0.41 ($0.05) $0.79 Mark-to-market impact of economic hedging activities - - - - 0.10 0.01 0.10 Unrealized gains related to NDT funds - - - - (0.12) - (0.12) Asset Impairments - - - - - - - Plant retirements and divestitures - - - - - - - Cost management program - - - - 0.01 - 0.02 Income Tax-Related Adjustments - - - - - (0.01) (0.01) Noncontrolling interests - - - - 0.03 - 0.03 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.15 $0.12 $0.10 $0.07 $0.44 ($0.05) $0.83 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 64 Q4 2019 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation (continued) Three Months Ended December 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.15 $0.13 $0.07 $0.06 ($0.18) ($0.07) $0.16 Mark-to-market impact of economic hedging activities - - - - 0.18 - 0.19 Unrealized losses related to NDT funds - - - - 0.25 - 0.25 Plant retirements and divestitures - - - - 0.10 - 0.10 Cost management program - - - - 0.01 - 0.02 Gain on contract settlement - - - - (0.06) - (0.06) Noncontrolling interests - - - - (0.08) - (0.08) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.15 $0.13 $0.07 $0.07 $0.23 ($0.07) $0.58 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 65 Q4 2019 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation Twelve Months Ended December 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.71 $0.54 $0.37 $0.49 $1.16 ($0.25) $3.01 Mark-to-market impact of economic hedging activities - - - - 0.18 0.02 0.20 Unrealized gains related to NDT funds - - - - (0.31) - (0.31) Asset Impairments - - - - 0.13 - 0.13 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - 0.01 0.04 - 0.05 Litigation settlement gain - - - - (0.02) - (0.02) Asset retirement obligation - - - - (0.09) - (0.09) Change in environmental liabilities - - - 0.02 - - 0.02 Income Tax-Related Adjustments - - - - 0.01 - 0.01 Noncontrolling interests - - - - 0.09 - 0.09 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.71 $0.55 $0.37 $0.52 $1.31 ($0.23) $3.22 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 66 Q4 2019 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation (continued) Twelve Months Ended December 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.69 $0.47 $0.32 $0.41 $0.38 ($0.20) $2.07 Mark-to-market impact of economic hedging activities - - - - 0.25 0.01 0.26 Unrealized losses related to NDT funds - - - - 0.35 - 0.35 Asset Impairments - - - - 0.04 - 0.04 Plant retirements and divestitures - - - - 0.53 - 0.53 Cost management program - - - - 0.04 - 0.05 Asset retirement obligation - - - 0.02 - - 0.02 Gain on contract settlement - - - - (0.06) - (0.06) Income Tax-Related Adjustments - - - (0.01) (0.03) 0.01 (0.02) Noncontrolling interests - - - - (0.12) - (0.12) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.69 $0.48 $0.33 $0.42(1) $1.39 ($0.18) $3.12 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. (1) Amount has been revised to reflect the correction of an error at PHI 67 Q4 2019 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2020 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; − Certain costs incurred to achieve cost management program savings; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to CENG exclusion items. 68 Q4 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) (2) Exelon FFO/Debt = FFO (a) Adjusted Debt (b) Exelon FFO Calculation(2) GAAP Operating Income + Depreciation & Amortization = EBITDA - Interest Expense +/- Cash Taxes + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) Exelon Adjusted Debt Calculation(1) Long-Term Debt (including current maturities) + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Pension/OPEB Imputed Debt (after-tax) + AR Securitization Imputed Debt - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment 69 Q4 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations(1) ExGen Debt/EBITDA = Net Debt (a) ExGen Debt/EBITDA = Net Debt (c) Operating EBITDA (b) Excluding Non-Recourse Operating EBITDA (d) ExGen Net Debt Calculation ExGen Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) ExGen Operating EBITDA Calculation ExGen Operating EBITDA Calculation Excluding Non- Recourse GAAP Operating Income + Depreciation & Amortization GAAP Operating Income = EBITDA + Depreciation & Amortization +/- GAAP to Operating Adjustments = EBITDA = Operating EBITDA (b) +/- GAAP to Operating Adjustments - EBITDA from Projects Financed by Non-Recourse Debt = Operating EBITDA Excluding Non-Recourse (d) (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures 70 Q4 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy EXC Q4 2019 Operating TTM ROE Reconciliation ($M) PHI Utilities Consolidated EU Utilities Net Income (GAAP) $488 $1,577 $2,065 Operating Exclusions $24 $6 $30 Adjusted Operating Earnings $512 $1,583 $2,095 Average Equity $5,557 $15,355 $20,913 Operating TTM ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 9.2% 10.3% 10.0% Legacy EXC Q4 2018(1) Operating TTM ROE Reconciliation ($M) PHI Utilities Consolidated EU Utilities Net Income (GAAP) $400 $1,437 $1,836 Operating Exclusions $25 $7 $32 Adjusted Operating Earnings $425 $1,444 $1,869 Average Equity $5,122 $14,245 $19,367 Operating TTM ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 8.3% 10.1% 9.6% Note: Represents the twelve-month period ending December 31, 2019 and December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). (1) Q4 2018 TTM ROE* for PHI and Consolidated EU was changed from 8.4% and 9.7%, respectively, to 8.3% and 9.6%, respectively, to reflect the correction of an error at PHI 71 Q4 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations 2020 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $825 $1,500 $825 $1,150 $5,225 ($150) $9,375 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - ($450) - ($450) AR Securitization - - - - ($750) - ($750) Adjusted Cash Flow from Operations (Non-GAAP) $825 $1,500 $825 $1,150 $3,750 ($150) $7,900 2020 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $525 $800 $300 $400 ($3,150) $275 ($850) Dividends paid on common stock $250 $500 $350 $375 $1,875 ($1,850) $1,500 AR Securitization - - - - $750 - $750 Financing Cash Flow (Non-GAAP) $775 $1,300 $650 $775 ($525) ($1,575) $1,400 Exelon Total Cash Flow Reconciliation(1) 2020 GAAP Beginning Cash Balance $2,425 Adjustment for Cash Collateral Posted ($925) Adjusted Beginning Cash Balance(3) $1,500 Net Change in Cash (GAAP)(2) ($575) Adjusted Ending Cash Balance(3) $925 Adjustment for Cash Collateral Posted ($450) GAAP Ending Cash Balance $475 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. (3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity 72 Q4 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2019 2020 2021 GAAP O&M $4,725 $4,800 $4,750 Decommissioning(2) $200 $75 $75 Direct cost of sales incurred to generate revenues for certain Constellation and ($275) ($225) ($275) Power businesses(3) O&M for managed plants that are partially owned ($400) ($425) ($425) Other ($75) ($25) - Adjusted O&M (Non-GAAP) $4,175 $4,200 $4,150 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects asset retirement obligation update for TMI and earnings neutral O&M (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* 73 Q4 2019 Earnings Release Slides