Earnings Conference Call 1st Quarter 2019 May 2, 2019

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) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22, Commitments and Contingencies; (2) Exelon’s First Quarter 2019 Quarterly Report on Form 10-Q in (a) Part II, Other Information, ITEM 1A. Risk Factors; (b) Part 1, Financial Information, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, Financial Information, ITEM 1. Financial Statements: Note 16; 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 Q1 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, impairments of certain long-lived assets, certain amounts associated with plant retirements and divestitures, costs related to cost management programs 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 Q1 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’ presentation. 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 33 of this presentation. 4 Q1 2019 Earnings Release Slides

PHI Merger is Delivering on Its Promises Operational Performance •ACE: Frequency of outages reduced by 22%, restoration times improved by 17% •Delmarva: Frequency of outages reduced by 34%, restoration times improved by 2% •Pepco: Frequency of outages reduced by 30%, restoration times improved by 28% Economic and Workforce Development •More than $470M in total economic impact in our communities •Invested in workforce development including partnering with District of Columbia in opening the DC Infrastructure Academy •$313M in diverse spend in 2018 representing 22-29% of each company’s total procurement spend Community Impact •85,000 volunteer hours •More than $15M in charitable giving across our PHI communities supporting hundreds of local partners More Constructive Regulatory Environment •Constructive settlements in all PHI jurisdictions including the first settlements at Pepco DC and Pepco Maryland since the 1980s •Enacted legislation in Delaware to create capital trackers for reliability investments •New Jersey Board of Public Utilities approved regulations that allow for tracker recovery of certain capital investments Customer Satisfaction is at all time highs at ACE, Delmarva and Pepco 5 Q1 2019 Earnings Release Slides

1st Quarter Results Q1 2019 EPS Results(1) $0.93 $0.87 • GAAP earnings were $0.93/share in Q1 2019 vs. $0.60/share in Q1 ExGen $0.37 $0.30 2018 • Adjusted operating earnings* were BGE $0.17 $0.17 $0.87/share in Q1 2019 vs. $0.96/share in Q1 2018, which was PECO $0.17 $0.17 above the midpoint of our guidance range of $0.80-$0.90/share PHI $0.12 $0.12 ComEd $0.16 $0.16 HoldCo ($0.06) ($0.06) Q1 GAAP Earnings Q1 Adjusted Operating Earnings* (1) Amounts may not sum due to rounding 6 Q1 2019 Earnings Release Slides

Operating Highlights Exelon Utilities Operational Metrics Exelon Generation Operational Performance YTD 2019 (2) Operations Metric Exelon Nuclear Fleet BGE ComEd PECO PHI • Best in class performance across our Nuclear fleet: OSHA Recordable Rate o Q1 2019 Nuclear Capacity Factor: 97.1% Electric 2.5 Beta SAIFI (1) o Owned and operated Q1 2019 production of 39.2 Operations (Outage Frequency) TWh(2) 2.5 Beta CAIDI (Outage Duration) 44 100% Customer 98% Satisfaction 42 96% Customer Service Level % of 40 94% Capacity Factor Calls Answered in 92% Operations <30 sec 38 90% TWhrs 36 Abandon Rate 88% 34 86% Percent of Calls 84% Gas No Gas Responded to in <1 32 Operations Operations 82% Hour 30 80% Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 • Strong reliability metrics with BGE and ComEd achieving top TWhrs Capacity Factor decile performance in CAIDI • Each utility delivered on key customer operations metrics Fossil and Renewable Fleet with all utilities performing in top decile for Abandon Rate and ComEd and PECO achieving top decile in Service Level • Q1 2019 Renewables energy capture: 96.5% and Customer Satisfaction • Q1 2019 Power dispatch match: 97.8% • PECO and PHI achieved top decile performance in Gas Odor Response Q1 Q2 Q3 Q4 (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture 7 Q1 2019 Earnings Release Slides

Key Policy Updates Illinois Pennsylvania ZEC Litigation: ZEC Legislation (HB11/SB510): • On April 15, the U.S. Supreme Court denied certiorari • Bipartisan, bicameral legislation that amends the upholding the ZEC programs Pennsylvania Alternative Portfolio Standard (AEPS) to add a third tier for zero-emitting resources including nuclear Clean Energy Progress Act (HB2861/SB1789): • Pricing is tied to tier 1 resources and will range from $6.08 - • Protects Illinois’ right to enact clean energy policies by $7.90/MWh implementing full fixed resource requirement (FRR) under the PJM tariff by directing the Illinois Power Authority to • All nuclear in Pennsylvania would be eligible to participate procure clean bundled capacity for ComEd for ten years starting with June 1, 2023 delivery year • Will ensure 100% clean energy through 2032 • Guarantees customers save money in the first year Formula Rate Extension Legislation (HB3152/SB2080): • Would extend the formula rate beyond the 2022 expiration New Jersey Energy Price Formation Reforms ZEC Legislation: Fast Start: • On April 18, the New Jersey BPU voted 4 to 1 to award ZECs • On April 18, FERC approved energy pricing reform for fast to Hope Creek and Salem 1 and 2 start resources requiring a 1 hour minimum notification and • The award is for 3 years plus a stub year. Payment will occur run-time within 90 days of the end of each energy year. For the first • PJM must submit a compliance filing by July 31, 2019 which energy year (from April 18, 2019 to May 31, 2019), payment includes an implementation date is expected by late August 2019. Reserves Price Formation: • PJM filed 206 petition to amend its tariff to improve the pricing of reserves • Requested order by December 15, 2019 8 Q1 2019 Earnings Release Slides

Exelon is Ideally Situated to Help Meet Climate Goals Deliberately Built Clean Fleet Carbon Reduction Goals Exelon Generation is the largest zero-carbon generator Despite being the lowest carbon intensive – producing 1 out of every 9 zero-carbon MWhs in the generation, we have set a goal of an US – after executing on a strategy to divest or retire additional 15% reduction of GHG coal-fired generation and improve the output of zero- emissions from our internal operations carbon nuclear fleet 1,622 1,386 1,429 • Between 2010 – 2017, retired or sold more than 2,000 968 1,094 738 805 MWs of coal-fired generation 479 • Developed or bought 1,500 MWs of renewable generation 105 • Increased output of nuclear fleet by more than 550 MWs EXC NEE D CPN DUK SO XEL NRG AEP • Invested in clean, efficient natural gas generation lbs/MWh(1) Support Policies to Reduce GHG Emissions Enabling a Carbon Free Future Exelon is a founding member From generation to transmission to distribution, our of the Climate Leadership Council – sustainability strategy focuses on creating systems and to advocate for a carbon fee-and- policies that enable integrated clean energy solutions dividend program and connections for our customers Support legislation and regulation to expand electric vehicle infrastructure at the state and federal level Support 100% clean energy standards (1) Reflects 2016 regulated and non-regulated generation. Excludes EDF’s equity ownership share of the CENG Joint venture for Exelon. Source: Benchmarking Air Emissions, June 2018; https://www.mjbradley.com/sites/default/files/Presentation_of_Results_2018.pdf 9 Q1 2019 Earnings Release Slides

1st Quarter Adjusted Operating Earnings* Drivers Q1 2019 Adjusted Operating EPS* Results Q1 2019 vs. Guidance of $0.80 - $0.90 $0.87 • Adjusted (non-GAAP) operating earnings drivers versus guidance: ExGen $0.30 Exelon Utilities – Timing of O&M BGE $0.17 Exelon Generation PECO $0.17 – Timing of O&M (1) $0.56 – NDT realized gains PHI $0.12 ComEd $0.16 HoldCo ($0.06) Q1 2019 Expect Q2 2019 Adjusted Operating Earnings* of $0.55 - $0.65 per share Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 10 Q1 2019 Earnings Release Slides

Q1 2019 Adjusted Operating Earnings* Waterfall $0.04 Distribution and Transmission Rate Increases $0.04 Decreased Storm Costs(1) $0.01 Decreased Storm Costs $0.02 Distribution Rate Increases ($0.01) Other $0.05 ($0.01) Interest Expense $0.04 ($0.03) Other $0.96 $0.05 ($0.19) ($0.01) $0.02 Distribution Rate Increases ($0.04) $0.87 $0.02 Decreased Storm Costs(1) $0.01 Distribution Investment ($0.02) Other ($0.19) Market and Portfolio Conditions(2) ($0.10) Zero Emission Credit Revenue(3) $0.04 Capacity Pricing $0.06 Other(4) Q1 2018 ComEd PECO BGE PHI ExGen(5) Corp Q1 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) Primarily reflects the absence of revenue recognized in the first quarter 2018 related to zero emissions credits generated in Illinois from June through December 2017 (4) Primarily reflects the elimination of activity attributable to noncontrolling interests, primarily for CENG (5) Drivers reflect CENG ownership at 100% 11 Q1 2019 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q1 2019: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities PHI Utilities 10.0% $30.4/10.5% $41.2/10.2% 8.0% $10.8/9.3% 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 Q1 2019 9.3% 10.5% 10.2% Q4 2018 8.4% 10.1% 9.7% Note: Represents the twelve-month period ending March 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. 12 Q1 2019 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec ROE / Requirement Order Equity Ratio BGE (2) 9.80% / FO $64.9M (2) Jan 4, 2019 Gas 52.85% (1) 9.60% / ACE(3) $70.0M Mar 13, 2019 SA FO 49.94% Pepco MD (1) 10.30% / CF IT RT EH IB FO $27.2M Aug 13, 2019 Electric 50.46% (1) 8.91% / (4) ($6.4M) Dec 2019 ComEd CF IT RT EH IB RB FO 47.97% 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) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (3) Per Settlement Agreement filed on March 4, 2019 and approved on March 13, 2019 (4) Anticipated schedule, actual dates will be determined by ALJ at status hearing 13 Q1 2019 Earnings Release Slides

Utility CapEx Update Pepco’s Harrison Substation Modernization • Forecasted project cost: − $190 million • In service date: − In service by end of Q4 2019; remediation and removal of temporary substation completed by Q4 2020 • Project scope: − Rebuild existing substation from a 56MVA (34/4kV & 34/13kV) dual voltage substation to a 140MVA (138/13kV) substation − New substation addresses aging infrastructure that will service loads of two Metro stations as well as key commercial facilities − Improvements also expand regional transmission capacity, allowing for future load growth; vintage substation was approaching 90% capacity Continuation of Gas Mains and Services Replacement Program in Baltimore • Forecasted project cost: − $732 million • In service date: − Multiple in service dates from 2019 to 2023 • Project scope: − Replace ~240 miles of gas mains and associated services by the end of 2023 − Improves safety and reliability of the distribution system and reduces environmental risks as leak-prone gas infrastructure is replaced − Recovered through Strategic Infrastructure Development and Enhancement (STRIDE) surcharge − Drives economic development as STRIDE has created 600 full-time jobs in the BGE territory since 2014 14 Q1 2019 Earnings Release Slides

Exelon Generation: Gross Margin Update March 31, 2019 Change from December 31, 2018 Gross Margin Category ($M)(1) 2019 2020 2021 2019 2020 2021 Open Gross Margin(2,5) $4,200 $4,100 $3,800 $(150) $50 $50 (including South, West, New England, Canada hedged gross margin) Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 - - - Mark-to-Market of Hedges(2,3) $550 $250 $100 $300 - - Power New Business / To Go $350 $650 $850 $(150) $(50) $(50) Non-Power Margins Executed $300 $150 $150 $100 - - Non-Power New Business / To Go $200 $350 $400 $(100) - - Total Gross Margin*(4,5) $7,650 $7,400 $7,150 - - - Recent Developments • Total Gross Margin is flat in all years due to changes in power prices offset by our hedges and execution of $150M, $50M and $50M of power new business in 2019, 2020 and 2021, respectively • Behind ratable hedging position reflects the fundamental upside we see in power prices ― ~8-11% behind ratable in 2020 when considering cross commodity hedges ― ~1-4% 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 March 31, 2019 market conditions (5) Reflects TMI retirement by September 2019 15 Q1 2019 Earnings Release Slides

Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Exelon S&P FFO/Debt %*(1,4) ExGen Debt/EBITDA Ratio*(5) 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 2019 Target 2019 Target Credit Ratings by Operating Company Current Ratings(2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3(3) 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) Table reflects senior unsecured ratings as of March 31, 2019 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL and Pepco. Exelon’s S&P Issuer credit rating (not shown in table) is BBB+ as of March 31, 2019. (3) ACE is on “Positive” outlook at Moody’s; all other ratings have a “Stable” outlook (4) Exelon Corp downgrade threshold (red dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp (5) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* 16 Q1 2019 Earnings Release Slides

The Exelon Value Proposition ▪ Regulated Utility Growth with utility EPS rising 6-8% annually from 2018- 2022 and rate base growth of 7.8%, representing an expanding majority of earnings ▪ ExGen’s strong free cash generation will provide ~$4.2B for utility growth and reduce debt by ~$2.5B over the next 4 years ▪ 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 2022 planning horizon ▪ Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 5% annual dividend growth through 2020(1), • Debt reduction; and, • Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors 17 Q1 2019 Earnings Release Slides

Additional Disclosures 18 Q1 2019 Earnings Release Slides

2019 Projected Sources and Uses of Cash Total Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(8) Exelon Utilities Balance (2) (1) All amounts rounded to the nearest Beginning Cash Balance 1,825 $25M. Figures may not add due to Adjusted Cash Flow from Operations(2) 650 1,400 725 1,025 3,825 4,000 (300) 7,550 rounding Base CapEx and Nuclear Fuel(3) - - - - - (1,775) (50) (1,850) (2) Gross of posted counterparty Free Cash Flow* 650 1,400 725 1,025 3,825 2,225 (350) 5,700 collateral Debt Issuances 300 700 300 375 1,675 - - 1,675 (3) Figures reflect cash CapEx and Debt Retirements - (300) - - (300) (625) - (925) CENG fleet at 100% Project Financing n/a n/a n/a n/a n/a (100) n/a (100) (4) Other Financing primarily includes Equity Issuance/Share Buyback - - - - - - - - expected changes in money pool, renewable JV distributions, tax Contribution from Parent 200 250 150 225 825 - (825) - equity cash flows, EDF Tax Other Financing(4) 200 200 50 - 425 (125) 100 400 distributions and capital leases Financing(5) 700 850 500 600 2,625 (850) (725) 1,050 (5) Financing cash flow excludes Total Free Cash Flow* and Financing 1,350 2,250 1,225 1,625 6,450 1,375 (1,075) 6,750 intercompany dividends Utility Investment (1,125) (1,875) (975) (1,375) (5,325) - - (5,325) (6) ExGen Growth CapEx primarily ExGen Growth(3,6) - - - - - (150) - (150) includes Retail Solar and W. Acquisitions and Divestitures - - - - - 25 - 25 Medway Equity Investments - - - - - (25) - (25) (7) Dividends are subject to declaration by the Board of Directors Dividend(7) - - - - - - - (1,400) Other CapEx and Dividend (1,125) (1,875) (975) (1,375) (5,325) (150) - (6,900) (8) Includes cash flow activity from Holding Company, eliminations and Total Cash Flow 250 375 250 250 1,125 1,225 (1,075) (125) other corporate entities Ending Cash Balance(2) 1,700 Consistent and reliable free cash flows* Supported by a strong balance sheet Enable growth & value creation Strong balance sheet enables flexibility to Creating value for customers, Operational excellence and financial raise and deploy capital for growth communities and shareholders discipline drives free cash flow* reliability ✓ $1.4B of long-term debt at the utilities, net ✓ Investing $5.5B of growth CapEx, with ✓ Generating $5.7B of free cash flow*, of refinancing, to support continued growth $5.3B at the Utilities and $0.2B at ExGen including $2.2B at ExGen and $3.8B at the and retirement of $0.7B of ExGen debt Utilities Note: Numbers may not add due to rounding 19 Q1 2019 Earnings Release Slides

Exelon Utilities 20 Q1 2019 Earnings Release Slides

BGE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. Case No. 9484 • Case filed on June 8, 2018 seeking an increase in gas distribution revenues only Test Year August 1, 2017 – July 31, 2018 • The increase is primarily driven by infrastructure investments since 2015/2016, and includes Test Period 12 months actual moving revenues currently being recovered via the Common Equity Ratio 52.85%(1) STRIDE surcharge into base rates • The Commission issued its order on this case on (1) Rate of Return ROE: 9.80%; ROR: 7.09% January 4, 2019 Rate Base (Adjusted) $1.6B Revenue Requirement Increase $64.9M(1) Residential Total Bill % Increase ~2.4%(2) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 6/8/2018 Intervenor testimony 9/14/2018 Rebuttal testimony 10/12/2018 Evidentiary hearings 11/2/2018 – 11/16/2018 Initial briefs due 11/2018 Reply briefs due 12/2018 Commission order 1/4/2019 (1) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (2) Increase expressed as a percentage of a combined electric and gas residential customer total bill 21 Q1 2019 Earnings Release Slides

ACE Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. ER-18080925 • August 21, 2018, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities Test Year January 1, 2018 – December 31, 2018 (BPU) to increase distribution base rates Test Period 12 months actual • March 4, 2019, ACE filed a Settlement Agreement and requested an increase in revenue requirement Common Equity Ratio 49.94% of $70.0M • March 13, 2019, BPU approved settlement which Rate of Return ROE: 9.60%; ROR: 7.08% placed rates in effect on April 1, 2019 Rate Base (Adjusted) $1.5B Revenue Requirement Increase $70.0M(1) Residential Total Bill % Increase 6.12% Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 8/21/2018 Settlement Agreement 3/4/2019 Commission order 3/13/2019 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings 22 Q1 2019 Earnings Release Slides

Pepco MD (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Case No. 9602 • Pepco MD filed an application with the Maryland Public Service Commission (MDPSC) Test Year February 1, 2018 – January 31, 2019 on January 15, 2019, seeking an increase in Test Period 12 months actual electric distribution base rates • Size of ask is driven by continued investments Requested Common Equity Ratio 50.46% in electric distribution system to maintain and Requested Rate of Return ROE: 10.30%; ROR: 7.81% increase reliability and customer service • Forward looking reliability plant additions Proposed Rate Base (Adjusted) $2.0B through July 2019 ($4.3M of Revenue Requirement based on 10.30% ROE) included Requested Revenue Requirement Increase $27.2M in revenue requirement request Residential Total Bill % Increase 2.66% Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Filed rate case 1/15/2019 Intervenor testimony 4/12/2019 Rebuttal testimony 4/30/2019 Evidentiary hearings 5/21/2019 - 5/24/2019 Initial briefs 6/17/2019 Commission order expected 8/13/2019 23 Q1 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 Requested Common Equity Ratio 47.97% Requested Rate of Return ROE: 8.91%; ROR: 6.53% Proposed Rate Base (Adjusted) $11,372M Requested Revenue Requirement Increase ($6.4M)(1) Residential Total Bill % Increase (0.4%) Detailed Rate Case Schedule(2) Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 4/8/2019 Intervenor testimony 6/2019 Rebuttal testimony 7/2019 Evidentiary hearings 8/2019 Initial briefs 9/2019 Reply briefs 9/2019 Commission order expected 12/2019 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Anticipated schedule, actual dates will be determined by ALJ at status hearing 24 Q1 2019 Earnings Release Slides

Exelon Generation Disclosures March 31, 2019 25 Q1 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 26 Q1 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 27 Q1 2019 Earnings Release Slides

ExGen Disclosures Gross Margin Category ($M)(1) 2019 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)(2,5) $4,200 $4,100 $3,800 Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 Mark-to-Market of Hedges(2,3) $550 $250 $100 Power New Business / To Go $350 $650 $850 Non-Power Margins Executed $300 $150 $150 Non-Power New Business / To Go $200 $350 $400 Total Gross Margin*(4,5) $7,650 $7,400 $7,150 Reference Prices(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.88 $2.74 $2.65 Midwest: NiHub ATC prices ($/MWh) $26.00 $25.76 $24.59 Mid-Atlantic: PJM-W ATC prices ($/MWh) $30.11 $32.26 $31.04 ERCOT-N ATC Spark Spread ($/MWh) $12.18 $9.54 $6.58 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $29.71 $31.77 $32.77 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on March 31, 2019 market conditions (5) Reflects TMI retirement by September 2019 28 Q1 2019 Earnings Release Slides

ExGen Disclosures Generation and Hedges 2019 2020 2021 Exp. Gen (GWh)(1) 191,400 184,400 180,000 Midwest 97,000 96,400 95,300 Mid-Atlantic(2,6) 53,900 48,100 48,500 ERCOT 23,800 24,200 19,600 New York(2) 16,700 15,700 16,600 % of Expected Generation Hedged(3) 90%-93% 64%-67% 38%-41% Midwest 90%-93% 64%-67% 34%-37% Mid-Atlantic(2,6) 97%-100% 71%-74% 47%-50% ERCOT 79%-82% 54%-57% 27%-30% New York(2) 81%-84% 57%-60% 48%-51% Effective Realized Energy Price ($/MWh)(4) Midwest $28.50 $28.00 $28.00 Mid-Atlantic(2,6) $38.50 $37.00 $32.50 ERCOT(5) $2.00 $3.00 $3.50 New York(2) $34.50 $35.50 $31.50 (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 11 refueling outages in 2019, 14 in 2020, and 13 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.9%, 93.9%, and 94.1% in 2019, 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 (6) Reflects TMI retirement by September 2019 29 Q1 2019 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities Gross Margin* Sensitivities (with existing hedges)(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $90 $305 $485 - $1/MMBtu $(65) $(265) $(430) NiHub ATC Energy Price + $5/MWh $25 $155 $320 - $5/MWh $(20) $(155) $(320) PJM-W ATC Energy Price + $5/MWh $(5) $55 $135 - $5/MWh $10 $(55) $(130) NYPP Zone A ATC Energy Price + $5/MWh - $15 $35 - $5/MWh - $(15) $(35) Nuclear Capacity Factor +/- 1% +/- $30 +/- $35 +/- $30 (1) Based on March 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 30 Q1 2019 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) $8,000 8,000 $7,800 $7,750 7,500 $7,450 7,000 $7,100 $6,650 Approximate Gross ($ Margin* million) Gross Approximate 6,500 6,000 2019 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 March 31, 2019. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects TMI retirement by September 2019. 31 Q1 2019 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2020 Total Gross Margin* South, Mid- Row Item Midwest ERCOT New York West, NE & Atlantic Canada (A) Start with fleet-wide open gross margin $4.1 billion (B) Capacity and ZEC $1.9 billion (C) Expected Generation (TWh) 96.4 48.1 24.2 15.7 (D) Hedge % (assuming mid-point of range) 65.5% 72.5% 55.5% 58.5% (E=C*D) Hedged Volume (TWh) 63.1 34.9 13.4 9.2 (F) Effective Realized Energy Price ($/MWh) $28.00 $37.00 $3.00 $35.50 (G) Reference Price ($/MWh) $25.76 $32.26 $9.54 $31.77 (H=F-G) Difference ($/MWh) $2.24 $4.74 ($6.54) $3.73 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $140 $165 ($90) $35 (J=A+B+I) Hedged Gross Margin ($ million) $6,250 (K) Power New Business / To Go ($ million) $650 (L) Non-Power Margins Executed ($ million) $150 (M) Non-Power New Business / To Go ($ million) $350 (N=J+K+L+M) Total Gross Margin* $7,400 million (1) Mark-to-market rounded to the nearest $5M 32 Q1 2019 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2019 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,075 $7,825 $7,550 Other Revenues(4) $(175) $(175) $(150) Direct cost of sales incurred to generate revenues for certain $(250) $(250) $(250) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,650 $7,400 $7,150 Key ExGen Modeling Inputs (in $M)(1,5) 2019 Other(6) $125 Adjusted O&M*(7) $(4,325) Taxes Other Than Income (TOTI)(8) $(400) Depreciation & Amortization*(9) $(1,125) Interest Expense $(400) Effective Tax Rate 21.0% (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, gross receipts tax revenues and JExel Nuclear JV (5) ExGen amounts for O&M, TOTI, 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 and Bloom (7) Adjusted O&M* includes $200M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) TOTI excludes gross receipts tax of $150M (9) 2020 Depreciation & Amortization is favorable to 2019 by $50M, while 2021 Depreciation & Amortization is favorable to 2019 by $25M 33 Q1 2019 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 34 Q1 2019 Earnings Release Slides

Q1 QTD GAAP EPS Reconciliation Three Months Ended March 31, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.16 $0.17 $0.17 $0.12 $0.37 $(0.06) $0.93 Mark-to-market impact of economic hedging activities - - - - 0.03 - 0.03 Unrealized gains related to NDT funds - - - - (0.20) - (0.20) Plant retirements and divestitures - - - - 0.02 - 0.02 Cost management program - - - - 0.01 - 0.01 Noncontrolling interests - - - - 0.07 - 0.07 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.16 $0.17 $0.17 $0.12 $0.30 $(0.06) $0.87 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 35 Q1 2019 Earnings Release Slides

Q1 QTD GAAP EPS Reconciliation (continued) Three Months Ended March 31, 2018 ComEd PECO BGE PHI ExGen Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.17 $0.12 $0.13 $0.07 $0.14 ($0.02) $0.60 Mark-to-market impact of economic hedging activities - - - - 0.20 - 0.20 Unrealized losses related to NDT funds - - - - 0.07 - 0.07 Plant retirements and divestitures - - - - - - 0.01 Cost management program - - - - 0.10 - 0.10 Noncontrolling interests - - - - (0.02) - (0.02) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.17 $0.12 $0.13 $0.07 $0.49 ($0.02) $0.96 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 36 Q1 2019 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2019 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 incurred related to plant retirements; − Certain costs incurred to achieve cost management program savings; − Other unusual items; and − Generation's noncontrolling interest related to CENG exclusion items. 37 Q1 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 - GAAP Interest Expense +/- GAAP Current Income Tax (Expense)/Benefit + Nuclear Fuel Amortization +/- GAAP to Operating Adjustments +/- 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) - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet * 75% +/- 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 38 Q1 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 39 Q1 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy EXC Consolidated Q1 2019 Operating ROE Reconciliation ($M) PHI Utilities Utilities EU Net Income (GAAP) $454 $1,516 $1,970 Operating Exclusions $26 $7 $33 Adjusted Operating Earnings $479 $1,523 $2,003 Average Equity $5,171 $14,477 $19,648 Operating ROE (Adjusted Operating Earnings/Average Equity) 9.3% 10.5% 10.2% Legacy EXC Consolidated Q4 2018 Operating ROE Reconciliation ($M) PHI Utilities Utilities EU Net Income (GAAP) $405 $1,437 $1,842 Operating Exclusions $25 $7 $32 Adjusted Operating Earnings $430 $1,444 $1,874 Average Equity $5,142 $14,245 $19,387 Operating ROE (Adjusted Operating Earnings/Average Equity) 8.4% 10.1% 9.7% ExGen Adjusted O&M Reconciliation ($M)(1) 2019 GAAP O&M $4,950 Decommissioning(2) 125 Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (250) O&M for managed plants that are partially owned (400) Other (100) Adjusted O&M (Non-GAAP) $4,325 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* 40 Q1 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations 2019 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $650 $1,400 $725 $1,025 $4,200 ($300) $7,725 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - $100 - $100 Adjusted Cash Flow from Operations $650 $1,400 $725 $1,025 $4,000 ($300) $7,550 2019 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $475 $350 $150 $250 ($1,750) $200 ($350) Dividends paid on common stock $225 $500 $350 $350 $900 ($925) $1,400 Financing Cash Flow $700 $850 $500 $600 ($850) ($725) $1,050 Exelon Total Cash Flow Reconciliation(1) 2019 GAAP Beginning Cash Balance $1,250 Adjustment for Cash Collateral Posted $575 Adjusted Beginning Cash Balance(3) $1,825 Net Change in Cash (GAAP)(2) ($125) Adjusted Ending Cash Balance(3) $1,700 Adjustment for Cash Collateral Posted ($550) GAAP Ending Cash Balance $1,150 (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 41 Q1 2019 Earnings Release Slides