Earnings Conference Call Second Quarter 2019 August 1, 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 Second 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 Q2 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 Q2 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 32 of this presentation. 4 Q2 2019 Earnings Release Slides

Second Quarter Results Q2 2019 EPS Results(1) $0.60 $0.50 • GAAP earnings were $0.50/share in $0.21 ExGen $0.11 Q2 2019 vs. $0.56/share in Q2 2018 BGE $0.05 $0.05 PECO $0.10 $0.11 • Adjusted operating earnings* were $0.60/share in Q2 2019 vs. PHI $0.11 $0.11 $0.71/share in Q2 2018, which was at the midpoint of our guidance range of $0.55-$0.65/share ComEd $0.19 $0.19 HoldCo ($0.07) ($0.06) Q2 GAAP Earnings Q2 Adjusted Operating Earnings* (1) Amounts may not sum due to rounding 5 Q2 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 Q2 2019 Nuclear Capacity Factor: 95.1% Electric 2.5 Beta SAIFI o Owned and operated Q2 2019 production of 38.8 (Outage Frequency)(1) Operations TWh 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% 84% Gas No Gas Gas Odor Response 32 Operations Operations 82% 30 80% • Strong reliability metrics across our utilities with ComEd in the top decile Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 Q4 18 Q1 19 Q2 19 performance in both CAIDI and SAIFI TWhrs Capacity Factor • Each utility continued to deliver on key customer operations metrics: o ComEd and PHI achieved top decile performance in Service Level and Abandon Rate Fossil and Renewable Fleet o BGE, ComEd and PECO recorded top decile performance in Customer Satisfaction • Q2 2019 Renewables Energy Capture: 96.0% o Delmarva Power achieved the number one ranking in J.D. Power’s 2019 • Q2 2019 Power Dispatch Match: 99.7% Electric Utility Residential Customer Satisfaction Study for the East Midsize Region; first Exelon utility to rank first Quartile 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 6 Q2 2019 Earnings Release Slides

Second Quarter Adjusted Operating Earnings* Drivers Q2 2019 Adjusted Operating EPS* Results Q2 2019 vs. Guidance of $0.55 - $0.65 $0.60 • Adjusted (non-GAAP) operating ExGen $0.21 earnings drivers versus guidance: Exelon Utilities BGE $0.05 – Timing of O&M PECO $0.11 – Unfavorable weather PHI $0.11 Exelon Generation $0.39 – Lower load volumes – Salem outage ComEd $0.19 – NDT realized gains(1) – Timing of O&M HoldCo ($0.06) Q2 2019 Expect Q3 2019 Adjusted Operating Earnings* of $0.80 - $0.90 per share Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 7 Q2 2019 Earnings Release Slides

Q2 2019 QTD Adjusted Operating Earnings* Waterfall $0.03 Distribution and Transmission $0.03 Distribution Rate Increases Rate Increases ($0.01) Unfavorable Weather ($0.01) Other ($0.01) Other $0.00 $0.02 $0.71 $0.02 $0.01 ($0.01) Interest Expense ($0.13) $0.60 $0.01 Distribution Rate Increases ($0.01) $0.01 Transmission Revenues ($0.01) Other $0.01 Other ($0.16) Market and Portfolio Conditions(1) $0.03 Zero Emission Credit Revenue(2) $0.02 Nuclear Outages(3) ($0.02) Other 2018 ComEd PECO BGE PHI ExGen(4) Corp 2019 Note: Amounts may not sum due to rounding (1) Primarily reflects lower realized energy prices (2) Primarily reflects an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019 (3) Reflects a decrease in nuclear outage days in 2019, excluding Salem, partially offset by an increase in nuclear outage days at Salem in 2019 (4) Drivers reflect CENG ownership at 100% 8 Q2 2019 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q2 2019: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities 10.0% PHI Utilities $30.4/10.5% $41.2/10.2% 8.0% $10.8/9.1% 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 Q2 2019 9.1% 10.5% 10.2% Q1 2019 9.3% 10.5% 10.2% Note: Represents the twelve-month period ending June 30, 2019 and March 31, 2019. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Size of bubble based on rate base. 9 Q2 2019 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar ROE / Requirement Order Equity Ratio (6) Pepco MD (1,6) 9.60% / IT RT EH IB FO $10.3M Aug 13, 2019 Electric 50.46% (1,2) 8.91% / ComEd ($6.4M) Dec 4, 2019 CF IT RT EH IB RB FO 47.97% (1,3) 10.3% / BGE CF EH IB RB FO $148.7M Dec 20, 2019 IT RT 52.1% (1,5) Pepco DC(4) $162.0M 10.30% / CF IT RT EH IB May 1, 2020 Electric RB 3-Year MYP 50.46% 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) Through the discovery period in the current proceeding, ComEd agreed to ~($9M) in adjustments (3) Reflects $81.1M increase for electric and $67.6M increase for gas. Increase reflects $8.7M of STRIDE (gas) and $7.1M of ERI (electric) that will be transferred from the STRIDE and ERI surcharges to base rates. (4) Procedural schedule as proposed by the Company in its initial application; Commission has not yet adopted a procedural schedule. (5) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $85M, $40M and $37M with rates effective May 1, 2020, January 1, 2021 and January 1, 2022, respectively. (6) Reflects Chief Public Utility Law Judge (CPULJ) recommendation received on July 9 10 Q2 2019 Earnings Release Slides

Featured Utility Capital Investments DC Power Line Undergrounding (DC PLUG) Pepco Partnership • Forecasted project cost: − Total project cost of $500 million to be shared equally with District Department of Transportation (DDOT) • In service date: − Multiple in service dates contingent on DC PSC approval of biennial filings scheduled through 2021 − DC PLUG initiative broke ground on June 14, 2019 • Project scope: − Partnership with DDOT focused on the underground placement of vulnerable distribution power lines − Up to 30 distribution voltage feeders to be installed underground − Improves grid resiliency and reliability by reducing risk of power outages caused by storms and supports faster restoration of customer interruptions ComEd’s Substation Expansion to Meet Data Center Growth • Forecasted project cost: − $48.5 million • In service date: − Project completed as of May 2019 • Project scope: − Installed a new distribution terminal and associated equipment, including an indoor switchgear building, three medium power transformers and twelve 138kV circuit breakers − The expanded substation provides capacity to power the equivalent of 45,000 homes and will support three new data centers in the Itasca/Elk Grove technology corridor near O’Hare airport − Enhances system reliability and resiliency by protecting equipment from weather and wildlife, while also allowing for further digitization of existing technologies 11 Q2 2019 Earnings Release Slides

Exelon Generation: Gross Margin Update June 30, 2019 Change from March 31, 2019 Gross Margin Category ($M)(1) 2019 2020 2021 2019 2020 2021 Open Gross Margin(2,5) $3,600 $3,550 $3,300 $(600) $(550) $(500) (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) $1,250 $750 $400 $700 $500 $300 Power New Business / To Go $250 $600 $800 $(100) $(50) $(50) Non-Power Margins Executed $350 $200 $150 $50 $50 - Non-Power New Business / To Go $150 $300 $400 $(50) $(50) - Total Gross Margin*(4,5) $7,650 $7,300 $6,900 - $(100) $(250) Recent Developments • 2019 Total Gross Margin* is flat due to declining power prices offset by our hedges and execution of a combined $150M of power and non-power new business • 2020 and 2021 Total Gross Margins* are down $100M and $250M, respectively, due to lower energy prices • Behind ratable hedging position reflects the fundamental upside we see in power prices ― ~10-13% behind ratable in 2020 when considering cross commodity hedges ― ~7-10% 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 June 30, 2019 market conditions (5) Reflects TMI retirement in September 2019 12 Q2 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% 21% 19%-21% 4.0 20% 3.0x S&P Threshold 3.0 15% 2.5x 2.0x 2.0 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 A2(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) Current senior unsecured ratings as of June 30, 2019, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (3) ACE was upgraded by Moody’s from A3 to A2 in June 2019 (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* 13 Q2 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 14 Q2 2019 Earnings Release Slides

Additional Disclosures 15 Q2 2019 Earnings Release Slides

2019 Adjusted Operating Earnings* Guidance $3.12(1) $3.00 - $3.30(2) Key Year-Over-Year Drivers • ExGen: Lower realized energy prices and absence of IL ZEC timing, partially offset by NJ ZEC uplift $1.20 - $1.30 $1.39 • BGE: Higher distribution and transmission revenue, partially offset by higher depreciation • PECO: Higher distribution and $0.30 - $0.40 transmission revenue, return to $0.33 normal storm (historical average), partially offset by higher depreciation $0.45 - $0.55 $0.48 • PHI: Higher distribution and transmission revenue and favorable O&M, partially offset by higher $0.45 - $0.55 $0.43 depreciation • ComEd: Increased capital investments to improve reliability in $0.70 - $0.80 $0.69 distribution and transmission, partially offset by lower treasury rates ($0.18) ($0.20) 2018 Actuals 2019 Guidance Note: Amounts may not add due to rounding (1) 2018 results based on 2018 average outstanding shares of 969M (2) 2019E earnings guidance based on expected average outstanding shares of 973M 16 Q2 2019 Earnings Release Slides

Q2 2019 YTD Adjusted Operating Earnings* Waterfall $0.04 Distribution Rate Increases $0.06 Distribution and $0.04 Decreased Storm Costs(1) Transmission Rate Increases ($0.01) Unfavorable Weather $0.01 Decreased Storm Costs ($0.01) Other $0.07 ($0.02) Interest Expense $0.02 $1.66 $0.06 ($0.03) Other $0.01 ($0.32) $0.03 Distribution Rate Increases $1.47 $0.02 Decreased Storm Costs(1) ($0.05) $0.01 Distribution and Energy ($0.01) Interest Expense Efficiency Investment ($0.02) Other $0.01 Transmission Revenues ($0.35) Market and Portfolio Conditions(2) ($0.01) Other ($0.08) Zero Emission Credit Revenue(3) $0.03 Nuclear Outages(4) $0.02 Capacity Pricing $0.06 Other(5) 2018 ComEd PECO BGE PHI ExGen(6) 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) 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, partially offset by an increase in New York ZEC prices and the approval of the New Jersey ZEC Program in the second quarter of 2019 (4) Reflects a decrease in nuclear outage days in 2019, excluding Salem, partially offset by an increase in nuclear outage days at Salem in 2019 (5) Primarily reflects the elimination of activity attributable to noncontrolling interests, primarily for CENG (6) Drivers reflect CENG ownership at 100% 17 Q2 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) 675 1,325 750 1,050 3,800 3,950 (275) 7,500 rounding. Base CapEx and Nuclear Fuel(3) - - - - - (1,775) (75) (1,850) (2) Gross of posted counterparty Free Cash Flow 675 1,325 750 1,050 3,800 2,175 (325) 5,650 collateral Debt Issuances 350 700 300 375 1,725 - - 1,725 (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, tax sharing from the parent, Contribution from Parent 200 250 150 200 800 - (800) - renewable JV distributions, tax Other Financing(4) 200 300 25 - 525 (125) 25 450 equity cash flows, EDF Tax Financing(5) 750 950 500 575 2,775 (850) (775) 1,150 distributions and capital leases Total Free Cash Flow and Financing 1,425 2,250 1,250 1,625 6,575 1,325 (1,100) 6,800 (5) Financing cash flow* excludes Utility Investment (1,200) (1,875) (1,000) (1,400) (5,450) - - (5,450) intercompany dividends ExGen Growth(3,6) - - - - - (150) - (150) (6) ExGen Growth CapEx primarily Acquisitions and Divestitures - - - - - 25 - 25 includes Retail Solar and W. Medway Equity Investments - - - - - (25) - (25) (7) Dividends are subject to declaration Dividend(7) - - - - - - - (1,400) by the Board of Directors Other CapEx and Dividend (1,200) (1,875) (1,000) (1,400) (5,450) (150) - (7,000) (8) Includes cash flow activity from Total Cash Flow 250 375 250 250 1,125 1,200 (1,100) (200) Holding Company, eliminations and (2) Ending Cash Balance 1,625 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 $5,650M of free cash flow*, ✓ $1,425M of long-term debt at the utilities, ✓ Investing $5,600M of growth CapEx, with including $2,175M at ExGen and $3,800M net of refinancing, to support continued $5,450M at the Utilities and $150M at at the Utilities growth and retirement of $725M of ExGen ExGen debt Note: Numbers may not add due to rounding 18 Q2 2019 Earnings Release Slides

Exelon Utilities 19 Q2 2019 Earnings Release Slides

BGE Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. Case No. 9610 • Case filed on May 24, 2019 seeking an increase in electric and gas distribution revenues Test Year August 1, 2018 – July 31, 2019 • The increase is primarily driven by the ongoing need for capital investments to maintain and modernize Test Period 8 months actual + 4 months estimated the electric and gas distribution systems for the Common Equity Ratio 52.1%(1) benefit of customers and includes moving revenues currently being recovered via the STRIDE and ERI (1) Rate of Return ROE: 10.3%; ROR: 7.25% Surcharges into Base Rates Rate Base (Adjusted) $5.4B • This Case also includes a depreciation study, which proposes an increase in depreciation expense of Revenue Requirement Increase $148.7M(1) $45.4M based on updated depreciation rates primarily related to insufficient recoveries of actual Residential Total Bill % Increase (2) 5.5% cost of removal incurred • The Commission is expected to issue an order on this case on December 20, 2019 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 Evidentiary hearings 10/25/2019 - 11/1/2019 Initial briefs due(3) 11/15/2019 Reply briefs due(3) 11/25/2019 Commission order expected 12/20/2019 (1) Reflects $81.1M increase for electric and $67.6M increase for gas. Increase reflects $8.7M of STRIDE (gas) and $7.1M of ERI (electric) that will be transferred from the STRIDE and ERI surcharges to base rates. (2) Increase expressed as a percentage of a combined electric and gas residential customer total bill (3) Initial Briefs are due two weeks after the end of the evidentiary hearings and Reply Briefs are due 10 days after Initial Briefs. Dates shown assume the evidentiary hearings end November 1, 2019. 20 Q2 2019 Earnings Release Slides

Pepco DC (Electric) Distribution Rate Case Filing Multi-Year Plan Case Filing Details Notes 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 Requested Common Equity Ratio 50.46% • Size of ask is driven by continued investments in electric distribution system to maintain and Requested Rate of Return ROE: 10.30%; ROR: 7.81% increase reliability and customer service 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B • MYP proposes five Performance Incentive (1) Mechanisms (PIMs) focused on system 2020-2022 Requested Revenue Requirement Increase $85M, $40M, $37M reliability, customer service and interconnection (1) 2020-2022 Residential Total Bill % Increase 7.1%, 4.2%, 3.7% Distributed Energy Resources (DER) Detailed Rate Case Schedule(2) May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Filed rate case 5/30/2019 Intervenor testimony 8/16/2019 Rebuttal testimony 10/4/2019 Evidentiary hearings 12/16/2019 - 12/20/2019 Initial briefs 1/16/2020 Reply briefs 1/31/2020 Commission order expected 5/1/2020 (1) Company proposed incremental revenue requirement increases with rates effective May 1, 2020, January 1, 2021 and January 1, 2022, respectively. (2) Procedural schedule as proposed by the Company in its initial application; Commission has not yet adopted a procedural schedule. 21 Q2 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 (1) • Size of ask is driven by continued investments Recommended Common Equity Ratio 50.46% in electric distribution system to maintain and (1) Recommended Rate of Return ROE: 9.60%; ROR: 7.45% increase reliability and customer service • On July 9, the CPULJ issued the proposed order (1) Recommended Rate Base (Adjusted) $2.0B with the final MDPSC order expected by August (1) 13 Recommended Revenue Requirement Increase $10.3M (1) Residential Total Bill % Increase 1.40% 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 (1) Reflects Chief Public Utility Law Judge (CPULJ) recommendation received on July 9 22 Q2 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)(1,2) 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 6/20/2019 Rebuttal testimony 7/17/2019 Evidentiary hearings 8/29/2019 Initial briefs 9/12/2019 Reply briefs 9/26/2019 Commission order expected 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) Through the discovery period in the current proceeding, ComEd agreed to ~($9M) in adjustments 23 Q2 2019 Earnings Release Slides

Exelon Generation Disclosures June 30, 2019 24 Q2 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 25 Q2 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 26 Q2 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) $3,600 $3,550 $3,300 Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 Mark-to-Market of Hedges(2,3) $1,250 $750 $400 Power New Business / To Go $250 $600 $800 Non-Power Margins Executed $350 $200 $150 Non-Power New Business / To Go $150 $300 $400 Total Gross Margin*(4,5) $7,650 $7,300 $6,900 Reference Prices(4) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.63 $2.54 $2.58 Midwest: NiHub ATC prices ($/MWh) $23.63 $22.92 $22.22 Mid-Atlantic: PJM-W ATC prices ($/MWh) $26.34 $27.63 $27.00 ERCOT-N ATC Spark Spread ($/MWh) $7.35 $8.46 $6.72 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $28.10 $29.32 $29.05 (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 June 30, 2019 market conditions (5) Reflects TMI retirement in September 2019 27 Q2 2019 Earnings Release Slides

ExGen Disclosures Generation and Hedges 2019 2020 2021 Exp. Gen (GWh)(1) 189,800 185,300 181,200 Midwest 97,600 96,500 95,600 Mid-Atlantic(2,6) 53,800 48,000 48,300 ERCOT 21,800 25,100 20,700 New York(2) 16,600 15,700 16,600 % of Expected Generation Hedged(3) 92%-95% 70%-73% 40%-43% Midwest 93%-96% 74%-77% 40%-43% Mid-Atlantic(2,6) 93%-96% 72%-75% 49%-52% ERCOT 86%-89% 62%-65% 37%-40% New York(2) 85%-88% 61%-64% 17%-20% Effective Realized Energy Price ($/MWh)(4) Midwest $29.00 $28.00 $28.00 Mid-Atlantic(2,6) $39.00 $38.00 $32.50 ERCOT(5) $4.50 $6.00 $6.50 New York(2) $37.00 $35.50 $24.50 (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 95.3%, 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 in September 2019 28 Q2 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 $50 $290 $510 - $1/MMBtu $(70) $(265) $(500) NiHub ATC Energy Price + $5/MWh $10 $120 $290 - $5/MWh $(10) $(120) $(290) PJM-W ATC Energy Price + $5/MWh $5 $50 $115 - $5/MWh - $(45) $(120) NYPP Zone A ATC Energy Price + $5/MWh $5 $20 $60 - $5/MWh $(5) $(20) $(60) Nuclear Capacity Factor +/- 1% +/- $20 +/- $30 +/- $25 (1) Based on June 30, 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 29 Q2 2019 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) 8,000 $7,700 $7,650 $7,600 7,500 $7,550 7,000 $7,100 6,500 $6,500 6,000 5,500 5,000 Approximate Gross ($ Margin* million) Gross Approximate 4,500 4,000 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 June 30, 2019. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects TMI retirement in September 2019. 30 Q2 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 $3.55 billion (B) Capacity and ZEC $1.9 billion (C) Expected Generation (TWh) 96.5 48.0 25.1 15.7 (D) Hedge % (assuming mid-point of range) 75.5% 73.5% 63.5% 62.5% (E=C*D) Hedged Volume (TWh) 72.9 35.3 15.9 9.8 (F) Effective Realized Energy Price ($/MWh) $28.00 $38.00 $6.00 $35.50 (G) Reference Price ($/MWh) $22.92 $27.63 $8.46 $29.32 (H=F-G) Difference ($/MWh) $5.08 $10.37 ($2.46) $6.18 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $370 $365 ($40) $60 (J=A+B+I) Hedged Gross Margin ($ million) $6,200 (K) Power New Business / To Go ($ million) $600 (L) Non-Power Margins Executed ($ million) $200 (M) Non-Power New Business / To Go ($ million) $300 (N=J+K+L+M) Total Gross Margin* $7,300 million (1) Mark-to-market rounded to the nearest $5M 31 Q2 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 $7,725 $7,300 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 $7,300 $6,900 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 32 Q2 2019 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 33 Q2 2019 Earnings Release Slides

Q2 QTD GAAP EPS Reconciliation Three Months Ended June 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.19 $0.10 $0.05 $0.11 $0.11 ($0.07) $0.50 Mark-to-market impact of economic hedging activities - - - - 0.07 - 0.07 Unrealized losses related to NDT funds - - - - 0.05 - 0.05 Plant retirements and divestitures - - - - (0.02) - (0.02) Cost management program - - - - - - 0.01 Litigation settlement gain - - - - (0.02) - (0.02) Noncontrolling interests - - - - 0.02 - 0.02 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.19 $0.11 $0.05 $0.11 $0.21 ($0.06) $0.60 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 34 Q2 2019 Earnings Release Slides

Q2 QTD GAAP EPS Reconciliation (continued) Three Months Ended June 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.17 $0.10 $0.05 $0.09 $0.18 ($0.04) $0.56 Mark-to-market impact of economic hedging activities - - - - (0.07) - (0.07) Unrealized losses related to NDT funds - - - - 0.08 - 0.08 Long-lived asset impairments - - - - 0.03 - 0.03 Plant retirements and divestitures - - - - 0.14 - 0.14 Cost management program - - - - 0.01 - 0.01 Change in environmental liabilities - - - - 0.01 - 0.01 Reassessment of deferred income taxes - - - - - (0.01) (0.01) Noncontrolling interests - - - - (0.04) - (0.04) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.17 $0.10 $0.05 $0.09 $0.34 ($0.05) $0.71 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 35 Q2 2019 Earnings Release Slides

Q2 YTD GAAP EPS Reconciliation Six Months Ended June 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.35 $0.28 $0.21 $0.23 $0.48 ($0.13) $1.43 Mark-to-market impact of economic hedging activities - - - - 0.09 0.01 0.10 Unrealized gains related to NDT funds - - - - (0.14) - (0.14) Long-lived asset impairments - - - - 0.01 - 0.01 Cost management program - - - - 0.01 - 0.02 Litigation settlement gain - - - - (0.02) - (0.02) Noncontrolling interests - - - - 0.08 - 0.08 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.35 $0.28 $0.21 $0.23 $0.51 $(0.12) $1.47 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 36 Q2 2019 Earnings Release Slides

Q2 YTD GAAP EPS Reconciliation (continued) Six Months Ended June 30, 2018 ComEd PECO BGE PHI ExGen Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.34 $0.22 $0.18 $0.15 $0.32 ($0.06) $1.16 Mark-to-market impact of economic hedging activities - - - - 0.13 - 0.13 Unrealized losses related to NDT funds - - - - 0.15 - 0.15 Long-lived asset impairments - - - - 0.03 - 0.03 Plant retirements and divestitures - - - - 0.23 - 0.23 Cost management program - - - - 0.01 - 0.02 Change in environmental liabilities - - - - 0.01 - 0.01 Reassessment of deferred income taxes - - - - - (0.01) (0.01) Noncontrolling interests - - - - (0.06) - (0.06) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.34 $0.22 $0.19 $0.16 $0.83 ($0.07) $1.66 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 37 Q2 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; − Asset impairments; − Impacts related to early plant retirements and divestitures; − Certain costs incurred to achieve cost management program savings; − Other unusual items; and − Generation's noncontrolling interest related to CENG exclusion items. 38 Q2 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 39 Q2 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 40 Q2 2019 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy EXC Q2 2019 Operating ROE Reconciliation ($M) PHI Utilities Consolidated EU Utilities Net Income (GAAP) $473 $1,539 $2,012 Operating Exclusions $25 $6 $31 Adjusted Operating Earnings $499 $1,545 $2,043 Average Equity $5,457 $14,665 $20,122 Operating ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 9.1% 10.5% 10.2% Legacy EXC Q1 2019 Operating ROE Reconciliation ($M) PHI Utilities Consolidated EU Utilities 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 $19,648 Operating ROE (Adjusted Operating Earnings/Average Equity) (Non-GAAP) 9.3% 10.5% 10.2% ExGen Adjusted O&M Reconciliation ($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* 41 Q2 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) $675 $1,325 $750 $1,050 $4,000 ($275) $7,525 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - $250 - $250 Adjusted Cash Flow from Operations (Non-GAAP) $675 $1,325 $750 $1,050 $3,950 ($275) $7,500 2019 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $525 $450 $150 $225 ($1,750) $150 ($250) Dividends paid on common stock $225 $500 $350 $350 $900 ($925) $1,400 Financing Cash Flow (Non-GAAP) $750 $950 $500 $575 ($850) ($775) $1,150 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) ($200) Adjusted Ending Cash Balance(3) $1,625 Adjustment for Cash Collateral Posted ($700) GAAP Ending Cash Balance $925 (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 42 Q2 2019 Earnings Release Slides