Earnings Conference Call 3rd Quarter 2018 November 1, 2018

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 2017 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 23, Commitments and Contingencies; (2) Exelon’s Third Quarter 2018 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 17; and (2) 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 Q3 2018 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, merger and integration related costs, impairments of certain long-lived assets, certain amounts associated with plant retirements and divestitures, costs related to a cost management program 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 Q3 2018 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 39 of this presentation. 4 Q3 2018 Earnings Release Slides

3rd Quarter Results Q3 2018 EPS Results(1,2) $0.88 • GAAP earnings were $0.76/share $0.76 in Q3 2018 vs. $0.85/share in Q3 2017 $0.33 ExGen $0.24 BGE $0.06 $0.07 • Adjusted operating earnings* were $0.88/share in Q3 2018 vs. $0.13 PECO $0.13 $0.85/share in Q3 2017, which is at the upper end of our guidance $0.20 PHI $0.19 range of $0.80-$0.90/share ComEd $0.20 $0.20 HoldCo ($0.07) ($0.05) GAAP Earnings Adjusted Operating Earnings* (1) Amounts may not sum due to rounding (2) Certain immaterial prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 5 Q3 2018 Earnings Release Slides

Operating Highlights Exelon Utilities Operational Metrics Exelon Generation Operational Performance Q3 2018 (2) Operations Metric Exelon Nuclear Fleet BGE ComEd PECO PHI • Best in class performance across our Nuclear fleet: OSHA Recordable Rate o Q3 2018 Nuclear Capacity Factor: 93.6% Electric 2.5 Beta SAIFI (1) o Owned and operated Q3 2018 production of 39.7 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% Q3 16 Q4 16 Q1 17 Q2 17 Q3 17 Q4 17 Q1 18 Q2 18 Q3 18 • Reliability performance remains strong in CAIDI and SAIFI across the utilities, while safety performance continues to TWhrs Capacity Factor improve Fossil and Renewable Fleet • Gas odor response remains strong in top decile across the • Q3 2018 Renewables energy capture: 95.7% utilities • Customer operation metrics are strong across all utilities • Q3 2018 Power dispatch match: 95.8% with BGE and ComEd performing in top decile for Customer • Wolf Hollow II and Colorado Bend unit 7 have Satisfaction and PHI in top decile for Service Level returned to service. Colorado Bend unit 8 will return Q1 Q2 to service in early November. 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 Q3 2018 Earnings Release Slides

Key Updates CostZEC Reductions Updates FERC CapacityZECS Order Market Reforms Committing to $200M in Seventh and Second Circuit Court FERC Capacity Market additional cost reductions with a of Appeals Uphold ZEC Programs: Proceeding: targeted run-rate date of 2021: • On September 13, the Seventh • On October 2, stakeholders filed • $100M at ExGen Circuit Court of Appeals affirmed comments in response to FERC’s • $100M at Business Services the dismissal of the Illinois ZEC request in its June order Company – approximately 50% complaint, upholding the legality • Exelon joined a coalition of savings will be allocated to of the program proposal supported by rate payer ExGen • On September 27, the Second advocates, attorneys general, Circuit affirmed dismissal of New environmental organizations, Savings due to our focus on York ZEC complaint renewable advocates and other improving efficiencies, eliminating • On October 9, the Seventh Circuit nuclear generators redundancies, and leveraging denied the petitioners’ request • Reply comments are due on innovation and technologies for rehearing November 6 • PJM requests FERC action in More than $900M in announced New Jersey: January 2019 to provide savings between 2015 – 2021 • Board of Public Utilities adequate time for the August relative to original plan completed meetings and 2019 PJM capacity auction hearings on implementation of ZEC program Fast Start: • On September 20, utilities filed • PJM fast start pricing has been tariff changes to recover ZEC fully briefed; awaiting decision related charges from FERC • ZEC applications are due on December 19 7 Q3 2018 Earnings Release Slides

3rd Quarter Adjusted Operating Earnings* Drivers Q3 2018 Adjusted Operating EPS* Results Q3 2018 vs. Guidance of $0.80 - $0.90 $0.88 Exelon Utilities – Favorable weather ExGen $0.33 – Reduced storm activity BGE $0.07 Exelon Generation (1) PECO $0.13 – NDT realized gains – Generation performance – Market conditions PHI $0.20 $0.55 – Higher transmission costs ComEd $0.20 HoldCo ($0.05) Q3 2018 Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 8 Q3 2018 Earnings Release Slides

QTD Adjusted Operating Earnings* Waterfall ($0.01) Interest Expense $0.01 Favorable Weather $0.88 ($0.01) $0.85 $0.05 ($0.03) $0.01 $0.01 $0.00 $0.01 Distribution Investment $0.01 Energy Efficiency Investment ($0.01) Other ($0.12) Market and Portfolio Conditions(1) $0.03 Rate Increases ($0.05) Nuclear Outages(2) $0.01 Favorable Weather $0.08 Tax Cuts and Jobs Act Savings $0.01 Other $0.04 Capacity Pricing $0.04 Illinois Zero Emission Credit Revenue ($0.02) Other 2017 (3) ExGen(4) ComEd PECO BGE PHI Corp 2018 Note: Amounts may not sum due to rounding (1) Primarily the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017 and lower realized energy prices (2) Decrease in volume due to an increase in outage days in 2018; additionally operating and maintenance expense increased due to an increase in outage days in 2018, excluding Salem (3) Certain immaterial prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 (4) Drivers reflect CENG ownership at 100% 9 Q3 2018 Earnings Release Slides

Raising Lower End of 2018 Guidance Range $2.90 - $3.20(1) $3.05 - $3.20(1) ExGen $1.35 - $1.45 $1.35 - $1.45 ExGen BGE $0.25 - $0.35 $0.25 - $0.35 BGE PHI $0.40 - $0.50 $0.40 - $0.50 PHI PECO $0.40 - $0.50 $0.40 - $0.50 PECO ComEd $0.60 - $0.70 $0.65 - $0.75 ComEd HoldCo ~($0.20) ~($0.20) HoldCo 2018 Initial Guidance 2018 Revised Guidance Note: Amounts may not sum due to rounding (1) 2018 Adjusted Operating Earnings* guidance based on expected average outstanding shares of 969M 10 Q3 2018 Earnings Release Slides

Trailing Twelve Month Earned ROEs* vs Allowed ROE Trailing Twelve Month Earned ROEs* Allowed ROE Q2 2018 TTM Earned ROE Q3 2018 TTM Earned ROE 9.9% 9.9% 10.3% 9.7% 10.2% 9.6% 9.4% 8.3% 7.7% 7.7% 7.7% 7.4% 5.4% ACE Delmarva Pepco Legacy Exelon Consolidated Utilities Exelon Utilities Note: Represents the twelve-month periods ending June 30, 2018 and September 30, 2018, respectively. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution and Electric Transmission). 11 Q3 2018 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun ROE / Requirement Order Equity Ratio (1,8) 8.69% / ComEd RT EH IB RB FO ($24.1M) Dec 2018 47.11% Delmarva (1,3) 9.70% / August 21, FO ($6.9M) Electric (DE) 50.52% 2018 Delmarva (1,4) 9.70% / RT EH SA FO ($3.5M) Q4 2018 Gas (DE) 50.52% Pepco (1,10) 9.525% / August 9, FO ($24.1M) Electric (DC) 50.44% 2018 PECO (1,5,9) RT EH SA IB RB FO $25M N/A Dec 2018 Electric BGE(2) (6) 10.5% / IT RT EH IB RB FO $82.4M (6) Jan 2019 Gas 52.85% (1) 10.10% / (7) CF IT RT EH IB RB $109.3M Q3 2019 ACE 50.22% 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: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, Delaware Public Service Commission, Public Service Commission of the District of Columbia, New Jersey Board of Public Utilities, and Pennsylvania Public Utility Commission and 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) BGE briefing schedule will be determined during or at the end of the evidentiary hearing (3) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on October 16, 2017, and implemented $5.8M full allowable rates on March 17, 2018, subject to refund. Per Settlement Agreement filed on June 27, 2018. Includes tax benefits from Tax Cuts and Jobs Act. (4) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on November 1, 2017, and implemented $3.9M full allowable rates on March 17, 2018, subject to refund. Per partial Settlement Agreement filed on September 7, 2018. Includes tax benefits from Tax Cuts and Jobs Act. (5) On October 18, 2018, the presiding Administrative Law Judges issued the Recommended Decision that the Settlement Agreement reached with all active parties be approved without modification. The black box settlement does not stipulate any ROE, Equity Ratio and Rate Base. The rate case settlement agreement is subject to PaPUC approval expected in December, with rates effective January 1, 2018. (6) Reflects $60.7M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (7) Procedural schedule as proposed by the Company. ACE plans to put interim rates in effect nine months after the filing date, subject to refund, as allowed by the regulations. (8) Original filing amount was ($22.9M). Recent discovery period removed additional ($1.2M) of revenue requirement to limit issues in the proceeding. (9) Reflects $96M revenue requirement less an estimated $71M in 2019 tax benefit (10) Per Settlement Agreement filed on April 17, 2018. Includes tax benefits from Tax Cuts and Jobs Act. 12 Q3 2018 Earnings Release Slides

Utility CapEx Update ComEd Completes AMI Smart Meter Installations • Forecasted project capital cost: − $920M; more than $20M under budget − AMI installations are part of the broader $2.6B Energy Infrastructure Modernization Act program • In service date: − Over 4M meters have been exchanged as of September 2018, which is 3 years ahead of the original schedule • Project scope: − Replaces existing legacy electric meters with digital smart meters and a wireless communications network − AMI improves grid reliability and enables operational efficiencies, while also empowering customers to take greater control of their energy consumption using online management tools and programs that offer efficiency and savings opportunities − Customers enrolled in the Peak Time Savings and Hourly Pricing programs have saved more than $5.6M and $19.5M, respectively ACE’s Churchtown Substation Expansion Project • Forecasted project cost: − $50M • In service date: − Improvements completed in April 2018; retirement of Deepwater Substation completed in October 2018 • Project scope: − Includes equipment upgrades for reliability and 230, 138 and 69 kV expansion for additional transmission capacity − Expansion improves reliability for our customers by replacing and upgrading obsolete equipment and by expanding regional transmission capacity 13 Q3 2018 Earnings Release Slides

Exelon Generation: Gross Margin Update September 30, 2018 Change from June 30, 2018 Gross Margin Category ($M)(1) 2018 2019 2020 2018 2019 2020 Open Gross Margin(2,5) $4,800 $4,300 $3,900 $100 $250 $100 (including South, West, Canada hedged gross margin) Capacity and ZEC Revenues(2,5,6) $2,300 $2,050 $1,900 - - - Mark-to-Market of Hedges(2,3) $350 $250 $250 $(50) $(150) $(50) Power New Business / To Go $100 $550 $800 $(50) $(50) - Non-Power Margins Executed $400 $200 $150 $50 $50 $50 Non-Power New Business / To Go $100 $300 $350 $(50) $(50) $(50) Total Gross Margin*(4,5) $8,050 $7,650 $7,350 - $50 $50 Recent Developments • Open Gross Margin (“OGM”) is up in 2018 due to higher NiHub, West Hub, and NY Zone A prices, partly offset by weaker ERCOT spark spreads • 2019 and 2020 OGM is up due to stronger ERCOT spark spreads and higher West Hub prices; 2019 OGM is also up on higher NiHub and New York Zone A prices • Mark-to-Market of Hedges is down in all years on higher prices, offset by the execution of Power New Business in 2018/2019 • Executed $50M of Non-Power New Business in all years • Behind ratable hedging position reflects the upside we see in power prices ― ~9-12% behind ratable in 2019 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 September 30, 2018, market conditions (5) Reflects Oyster Creek retirement in September 2018 and TMI retirement by September 2019 (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production. 2019 and 2020 include the favorable impact of NJ ZEC revenues. 14 Q3 2018 Earnings Release Slides

Cost Management is Integral to Our Business Strategy ExGen and BSC Cost Reductions Since Constellation Merger 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 CEG Merger Synergies of $170M in 2012, $350M in 2013, and $500M Run-Rate beginning in 2014 CENG Service Agreement Run-Rate Synergies of $70M (2013 EEI) $350M Cost Management Program (2015 EEI) PHI Merger Run-Rate Synergies of $130M Cost Reductions of $100M in 2018 and $125M in 2019 (Q3 2016 Earnings Call) Cost Reductions of $250M Run-Rate by 2020 (Q3 2017 Earnings Call) New Cost Reductions of $200M Run-Rate by 2021 AnnouncedCost Reductions (Q3 2018 Earnings Call) ExGen Forecast O&M* Q3 2018 ($M) Key Commentary Q3 ’18 Cost Reductions Other Adjustments(1) ExGen Total O&M • Committing to $200M in additional cost reductions ― $100M at ExGen 50 4,625 25 ― $100M at Business Services Company – 75 150 25 approximately 50% of savings will be 25 4,250 4,175 allocated to ExGen 4,125 • Since 2015, Exelon has announced more 2018 2019 2020 2021 than $900M of cost reductions (1) Primarily pension updates due to higher interest rates 15 Q3 2018 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% 22% 4.0 18%-20% 20% 3.0x 3.0 2.5x 15% 2.0x S&P Threshold 2.0 10% Book Excluding Non-Recourse 5% 1.0 0% 0.0 2018 Target 2018 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-(3) BBB(3) A-(3) A-(3) A-(3) A(3) A(3) A(3) Fitch BBB(3) BBB A A(3) A-(3) 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 November 1, 2018, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (3) Exelon Corp and all subsidiaries are on “Positive” outlook at S&P; Exelon Corp, PECO, and and BGE are on “Positive” outlook at Fitch; 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 Q3 2018 Earnings Release Slides

The Exelon Value Proposition ▪ Regulated Utility Growth with utility EPS rising 6-8% annually from 2017- 2021 and rate base growth of 7.4%, representing an expanding majority of earnings ▪ ExGen’s strong free cash generation will support utility growth while also reducing debt by ~$3B 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 2021 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 Q3 2018 Earnings Release Slides

Additional Disclosures 18 Q3 2018 Earnings Release Slides

YTD Adjusted Operating Earnings* Waterfall $0.04 Favorable Weather $0.01 Other ($0.04) Increased Storm Costs $2.55 $0.01 $0.04 $0.00 $0.00 $0.05 $0.39 $0.06 Rate Increases $2.06 $0.02 Favorable Weather $0.04 Distribution Investment ($0.03) Other $0.01 Energy Efficiency Investments ($0.01) Other $0.02 Increased Transmission Rates ($0.02) Increased Storm Costs $0.32 Zero Emission Credit Revenue(1) $0.15 Capacity Pricing $0.15 Tax Cuts and Jobs Act Savings $0.07 Nuclear Outages(2) ($0.27) Market and Portfolio Conditions(3) ($0.03) Other 2017 (4) ExGen(5) ComEd PECO BGE PHI Corp 2018 Note: Amounts may not sum due to rounding (1) Reflects the impacts of the New York Clean Energy and Illinois Zero Emission Standards, including the impact of zero emission credits generated in Illinois from June 1, 2017 through December 31, 2017 (2) Increase in volume due to a decrease in outage days in 2018; additionally operating and maintenance expense decreased due to a decrease in outage days in 2018, excluding Salem (3) Primarily lower realized energy prices and the absence of EGTP revenues net of purchased power and fuel expense resulting from its deconsolidation in the fourth quarter of 2017 (4) Certain immaterial prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income have been recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 (5) Drivers reflect CENG ownership at 100% 19 Q3 2018 Earnings Release Slides

2018 Projected Sources and Uses of Cash Total Exelon Cash (1) All amounts rounded to the nearest ($M)(1) BGE ComEd PECO PHI ExGen Corp(8) $25M. Figures may not add due to Utilities 2018E Balance rounding. Beginning Cash Balance*(2) 1,450 (2) Gross of posted counterparty Adjusted Cash Flow from Operations*(2) 750 1,650 650 1,100 4,175 3,800 175 8,150 collateral (3) Figures reflect cash CapEx and Base CapEx and Nuclear Fuel(3) 0 0 0 0 0 (1,975) (50) (2,025) CENG fleet at 100% Free Cash Flow* 750 1,650 650 1,100 4,175 1,825 125 6,125 (4) Other Financing primarily includes Debt Issuances 300 1,350 700 750 3,100 0 0 3,100 commercial paper, expected Debt Retirements 0 (850) (500) (275) (1,625) 0 0 (1,625) changes in money pool borrowings, Project Financing n/a n/a n/a n/a n/a (100) n/a (100) tax sharing from the parent, debt issue costs, tax equity cash flows, Equity Issuance/Share Buyback 0 0 0 0 0 0 0 0 capital leases, and renewable JV Contribution from Parent 100 500 50 350 1,000 0 (1,000) 0 distributions Other Financing(4) 50 0 50 (125) (25) 50 (50) (25) (5) Financing cash flow excludes Financing*(5) 475 1,000 300 700 2,475 (50) (1,050) 1,375 intercompany dividends Total Free Cash Flow and Financing 1,225 2,650 950 1,800 6,625 1,775 (925) 7,475 (6) ExGen Growth CapEx primarily includes Texas CCGTs, W. Medway, Utility Investment (1,000) (2,125) (850) (1,500) (5,475) 0 0 (5,475) and Retail Solar ExGen Growth(3,6) 0 0 0 0 0 (350) 0 (350) (7) Dividends are subject to Acquisitions and Divestitures 0 0 0 0 0 (25) 0 (25) declaration by the Board of Equity Investments 0 0 0 0 0 (25) 0 (25) Directors Dividend(7) 0 0 0 0 0 0 (1,325) (1,325) (8) Includes cash flow activity from Other CapEx and Dividend (1,000) (2,125) (850) (1,500) (5,475) (400) (1,325) (7,225) Holding Company, eliminations, and other corporate entities Total Cash Flow 225 525 100 275 1,150 1,375 (2,250) 275 Ending Cash Balance*(2) 1,725 Consistent and reliable free cash flows Supported by a strong balance sheet Enable growth & value creation Operational excellence and financial Strong balance sheet enables flexibility to Creating value for customers, discipline drives free cash flow reliability raise and deploy capital for growth communities and shareholders ✓ ✓ Generating $6.1B of free cash flow*, $1.5B of long-term debt at the utilities, net ✓ Investing $5.9B of growth capex, with including $1.8B at ExGen and $4.2B at the of refinancing, to support continued growth $5.5B at the Utilities and $0.4B at ExGen Utilities Note: Numbers may not add due to rounding 20 Q3 2018 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q3 2018: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities 11.0% 10.0% Pepco 9.0% Delmarva $4.7/8.3% $2.9/7.7% $28.0/10.2% 8.0% $37.8/9.6% 7.0% ACE $2.2/7.7% 6.0% 5.0% Earned(%)ROE 4.0% 3.0% 2.0% 1.0% 0.0% $0 $2 $4 $6 $8 $24 $26 $28 $30 $32 $34 $36 $38 $40 2018E Rate Base ($B) Note: Represents the twelve-month period ending September 30, 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. 21 Q3 2018 Earnings Release Slides

Shared Principles for FRR-RS Have Broad Support From Many Sectors Renewable Shared Principles Industry Community Stakeholders An FRR-RS mechanism should: • Protect customers from paying duplicate capacity • Preserve states’ abilities to achieve clean energy policy goals FERC should: Consumer • Require Fixed Resource Advocates Requirement – Resource Specific (FRR-RS) to allow load serving Environmental entities to buy capacity from all NGOs state-incentivized resources and receive full capacity credit for doing so • Allow for a smooth transition by giving states enough time to work through any difficult implementation issues before fully imposing the MOPR Numerous parties endorsed a shared set of principles and many others favorably cited those principles in their comments in Docket EL18-178 22 Q3 2018 Earnings Release Slides

Exelon Utilities 23 Q3 2018 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 6 months actual and 6 months estimated • Size of ask is primarily driven by increased depreciation expense, continued investment in Requested Common Equity Ratio 50.22% infrastructure to maintain and improve reliability and customer satisfaction, and higher O&M costs Requested Rate of Return ROE: 10.10%; ROR: 7.45% • Forward looking additions through June 2019 Proposed Rate Base (Adjusted) $1.6B ($9.8M of revenue requirement based on 10.10% ROE) included in revenue requirement request (1) Requested Revenue Requirement Increase $109.3M • Interim rates expected to go in effect in May 2019, Residential Total Bill % Increase 9.55% subject to refund, as allowed by the regulations Detailed Rate Case Schedule(2) Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Filed rate case 8/21/2018 Intervenor testimony 11/19/2018 Rebuttal testimony 12/21/2018 Evidentiary hearings 2/4/2019 – 2/15/2019 Initial briefs due 3/8/2019 Reply briefs due 3/22/2019 Commission order expected Q3 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) Procedural schedule as proposed by the Company 24 Q3 2018 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 Requested Common Equity Ratio 52.85%(1) STRIDE surcharge into base rates Requested Rate of Return ROE: 10.5%; ROR: 7.46%(1) Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase $82.4M(1) Residential Total Bill % Increase ~3.4%(2) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 06/08/2018 Intervenor testimony 09/14/2018 Rebuttal testimony 10/12/2018 Evidentiary hearings 11/2/2018 – 11/16/2018 Initial briefs due(3) 11/2018 Reply briefs due(3) 12/2018 Commission order expected 01/04/2019 (1) Reflects $60.7M 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 (3) Briefing schedule will be determined during or at the end of the evidentiary hearing 25 Q3 2018 Earnings Release Slides

ComEd Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 18-0808 • April 16, 2018, ComEd filed its annual distribution formula rate update with the Illinois Test Year January 1, 2017 – December 31, 2017 Commerce Commission seeking a decrease to Test Period 2017 Actual Costs + 2018 Projected Plant distribution base rates Additions • The decrease is primarily driven by an adjustment for forecasted tax benefits resulting Requested Common Equity Ratio 47.11% from federal tax reform, partially offset by Requested Rate of Return ROE: 8.69%; ROR: 6.52% continued investment in the electric grid, state tax rate increase, elimination of bonus Proposed Rate Base (Adjusted) $10,675M depreciation and weather/economic impacts Requested Revenue Requirement Decrease ($24.1M)(1,2) Residential Total Bill % Decrease (1%) Detailed Rate Case Schedule Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 4/16/2018 Intervenor testimony 6/28/2018 Rebuttal testimony 7/23/2018 Evidentiary hearings 8/28/2018 Initial briefs due 9/11/208 Reply briefs due 9/25/2018 Commission order expected 12/2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Original filing amount was ($22.9M). Recent discovery period removed additional ($1.2M) of revenue requirement to limit issues in the proceeding. 26 Q3 2018 Earnings Release Slides

Delmarva DE (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 17-0977 – Per Settlement (Black Box) • August 17, 2017, Delmarva DE filed an application with Delaware Public Service Test Year January 1, 2017 – December 31, 2017 Commission (DPSC) seeking an increase in electric Test Period 8 months actual and 4 months estimated distribution base rates • Size of ask is driven by continued investments in (2) Common Equity Ratio 50.52% electric distribution system to maintain and Rate of Return ROE: 9.70%; ROR: 6.78%(2) increase reliability and customer service • June 27, 2018, Delmarva DE filed a Settlement Rate Base (Adjusted) N/A Agreement and requested a decrease in revenue (2) Revenue Requirement Decrease ($6.9M)(1,2) requirement of ($6.9M) (2) • August 21, 2018, DPSC approved the settlement Residential Total Bill % Decrease (1.2%) Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 8/17/2017 Settlement agreement 6/27/2018 Settlement support testimony 6/27/2018 Evidentiary hearings 6/27/2018 Commission order 8/21/2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on October 16, 2017, and implemented $5.8M full allowable rates on March 17, 2018, subject to refund. Per Settlement Agreement filed on June 27, 2018. Includes tax benefits from Tax Cuts and Jobs Act. 27 Q3 2018 Earnings Release Slides

Delmarva DE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 17-0978 - Per Settlement (Black Box) • August 17, 2017, Delmarva DE filed an application with Delaware Public Service Test Year January 1, 2017 – December 31, 2017 Commission (DPSC) seeking an increase in Test Period 8 months actual and 4 months estimated gas distribution base rates • September 7, 2018, Delmarva Power filed a Requested Common Equity Ratio 50.52%(2) partial gas Settlement Agreement and Requested Rate of Return ROE: 9.70%; ROR: 6.78%(2) requested a decrease in revenue requirement of ($3.5M)(2) Proposed Rate Base (Adjusted) N/A • The partial Settlement Agreement resolves all Requested Revenue Requirement Decrease ($3.5M)(1,2) issues except a $3.5M regulatory asset related to the Interface Management Unit (2) Residential Total Bill % Decrease (2.6%) (IMU) batteries Detailed Rate Case Schedule Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 8/17/2017 Intervenor testimony 5/7/2018 Rebuttal testimony 7/6/2018 Settlement agreement 9/7/2018 Settlement support testimony 9/7/2018 Evidentiary hearings 9/7/2018 Commission order expected Q4 2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5M on November 1, 2017, and implemented $3.9M full allowable rates on March 17, 2018, subject to refund. Per partial Settlement Agreement filed on September 7, 2018. Includes tax benefits from Tax Cuts and Jobs Act. 28 Q3 2018 Earnings Release Slides

PECO Distribution Rate Case Filing Rate Case Settlement Details Notes Docket No. R-2018-3000164 • PECO filed an electric distribution base rate case on March 29, 2018 Test Year January 1, 2019 – December 31, 2019 • On October 18, 2018 the presiding Administrative Law Judges issued the Recommended Decision that the Test Period 12 Months Budget Settlement Agreement reached with all active parties Common Equity Ratio N/A be approved without modification. The black box settlement does not stipulate any ROE, Equity Ratio Rate of Return ROE: N/A; ROR: N/A and Rate Base. • The rate case settlement agreement is subject to Rate Base N/A PaPUC approval expected in December, with rates effective January 1, 2019 Revenue Requirement Increase (1,2) (2) $25M • The settlement amount of $96M represents 63% of Residential Total Bill % Increase 1.2% the $153M ask. This is in line with prior PA electric distribution rate case outcomes. Detailed Rate Case Schedule Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Pre-filing notice 2/27/2018 Filed rate case 3/29/2018 Intervenor testimony 6/26/2018 Rebuttal testimony 7/24/2018 Evidentiary hearings 8/21/2018 Initial briefs filed 9/07/2018 Reply briefs filed 9/17/2018 Commission order expected 12/01/2018 (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 $96M revenue requirement less an estimated $71M in 2019 tax benefit 29 Q3 2018 Earnings Release Slides

Pepco DC (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 1150 & 1151 – Per Settlement (Black Box) • December 19, 2017, Pepco DC filed an application with Public Service Commission of the Test Year January 1, 2017 – December 31, 2017 District of Columbia (PSCDC) seeking an increase in electric distribution base rates Test Period 8 months actual and 4 months estimated • Size of ask is driven by continued investments in Requested Common Equity Ratio 50.44%(2) electric distribution system to maintain and increase reliability and customer service Requested Rate of Return ROE: 9.525%; ROR: 7.45%(2) • April 17, 2018, Pepco DC filed a settlement agreement and requested a decrease in revenue Proposed Rate Base (Adjusted) N/A requirement of ($24.1M)(2) Requested Revenue Requirement Decrease ($24.1M)(1,2) • August 9, 2018, PSCDC approved settlement agreement which placed rates in effect on August Residential Total Bill % Decrease (0.7%)(2,3) 13, 2018 Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 12/19/2017 Settlement agreement 4/17/2018 Settlement support testimony 5/7/2018 Reply testimony 5/18/2018 Initial briefs 6/14/2018 Commission order 8/9/2018 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Per Settlement Agreement filed on April 17, 2018. Includes tax benefits from Tax Cuts and Jobs Act. (3) Modified/Extended Customer Base Rate Credit (CBRC) 30 Q3 2018 Earnings Release Slides

Exelon Generation Disclosures September 30, 2018 31 Q3 2018 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 32 Q3 2018 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 fossils fuels Zero Emissions and wholesale •Mid marketing •Portfolio expense Credits (ZEC) load transactions new business Management / •Power Purchase •Provided directly origination fuels Agreement (PPA) at a consolidated new business Costs and level for five major Revenues regions. Provided •Proprietary trading(3) •Provided at a indirectly for each consolidated level of the five major for all regions regions via (includes hedged Effective Realized gross margin for Energy Price South, West 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 & 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 five 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 & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin 33 Q3 2018 Earnings Release Slides

ExGen Disclosures Gross Margin Category ($M)(1) 2018 2019 2020 Open Gross Margin (including South, West & Canada hedged GM)(2,5) $4,800 $4,300 $3,900 Capacity and ZEC Revenues(2,5,6) $2,300 $2,050 $1,900 Mark-to-Market of Hedges(2,3) $350 $250 $250 Power New Business / To Go $100 $550 $800 Non-Power Margins Executed $400 $200 $150 Non-Power New Business / To Go $100 $300 $350 Total Gross Margin*(4,5) $8,050 $7,650 $7,350 Reference Prices(1) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) $2.94 $2.78 $2.65 Midwest: NiHub ATC prices ($/MWh) $27.62 $26.24 $24.92 Mid-Atlantic: PJM-W ATC prices ($/MWh) $36.54 $33.53 $31.59 ERCOT-N ATC Spark Spread ($/MWh) $4.06 $11.50 $10.30 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $31.86 $29.49 $27.89 New England: Mass Hub ATC Spark Spread ($/MWh) $6.80 $6.88 $6.27 ALQN Gas, 7.5HR, $0.50 VOM (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 September 30, 2018, market conditions (5) Reflects Oyster Creek retirement in September 2018 and TMI retirement by September 2019 (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production. 2019 and 2020 include the favorable impact of NJ ZEC revenues. 34 Q3 2018 Earnings Release Slides

ExGen Disclosures Generation and Hedges 2018 2019 2020 Exp. Gen (GWh)(1) 196,300 201,900 192,900 Midwest 96,600 97,000 96,500 Mid-Atlantic(2,6) 60,300 54,000 48,500 ERCOT 16,900 25,500 23,700 New York(2,6) 16,200 16,600 15,600 New England 6,300 8,800 8,600 % of Expected Generation Hedged(3) 98%-101% 82%-85% 48%-51% Midwest 98%-101% 79%-82% 44%-47% Mid-Atlantic(2,6) 100%-103% 94%-97% 61%-64% ERCOT 98%-101% 78%-81% 49%-52% New York(2,6) 98%-101% 93%-96% 57%-60% New England 78%-81% 23%-26% 13%-16% Effective Realized Energy Price ($/MWh)(4) Midwest $30.00 $28.50 $28.00 Mid-Atlantic(2,6) $39.00 $37.50 $37.00 ERCOT(5) ($2.00) $2.00 $1.00 New York(2,6) $36.00 $32.00 $30.00 New England(5) $7.00 $6.00 $25.50 (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2018, 11 in 2019, and 14 in 2020 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.3%, 94.6% and 93.9% in 2018, 2019, and 2020, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2019 and 2020 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 and New England (6) Reflects Oyster Creek retirement in September 2018 and TMI retirement by September 2019 35 Q3 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities Gross Margin* Sensitivities (with existing hedges)(1) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $(10) $190 $445 - $1/MMBtu $20 $(145) $(395) NiHub ATC Energy Price + $5/MWh - $100 $265 - $5/MWh - $(100) $(265) PJM-W ATC Energy Price + $5/MWh $(5) $20 $95 - $5/MWh $5 - $(90) NYPP Zone A ATC Energy Price + $5/MWh - - $30 - $5/MWh - $(5) $(30) Nuclear Capacity Factor +/- 1% +/- $10 +/- $35 +/- $30 (1) Based on September 30, 2018, 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 36 Q3 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) $8,100 8,000 $8,000 $7,850 $7,900 7,500 $7,400 7,000 $6,950 Approximate Gross ($ Margin* million) Gross Approximate 6,500 6,000 2018 2019 2020 (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 2019 and 2020 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 September 30, 2018. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Oyster Creek retirement in September 2018 and TMI retirement by September 2019 37 Q3 2018 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2019 Total Gross Margin* South, Mid- New Row Item Midwest ERCOT New York West & Atlantic England Canada (A) Start with fleet-wide open gross margin $4.3 billion (B) Capacity and ZEC $2.05 billion (C) Expected Generation (TWh) 97.0 54.0 25.5 16.6 8.8 (D) Hedge % (assuming mid-point of range) 80.5% 95.5% 79.5% 94.5% 24.5% (E=C*D) Hedged Volume (TWh) 78.1 51.6 20.3 15.7 2.2 (F) Effective Realized Energy Price ($/MWh) $28.50 $37.50 $2.00 $32.00 $6.00 (G) Reference Price ($/MWh) $26.24 $33.53 $11.50 $29.49 $6.88 (H=F-G) Difference ($/MWh) $2.26 $3.97 ($9.50) $2.51 ($0.88) (I=E*H) Mark-to-Market value of hedges ($ million)(1) $175 $205 ($195) $40 $0 (J=A+B+I) Hedged Gross Margin ($ million) $6,600 (K) Power New Business / To Go ($ million) $550 (L) Non-Power Margins Executed ($ million) $200 (M) Non-Power New Business / To Go ($ million) $300 (N=J+K+L+M) Total Gross Margin* $7,650 million (1) Mark-to-market rounded to the nearest $5M 38 Q3 2018 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2018 2019 2020 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,525 $8,125 $7,800 Other Revenues(4) $(200) $(175) $(200) Direct cost of sales incurred to generate revenues for certain $(275) $(300) $(250) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $8,050 $7,650 $7,350 Key ExGen Modeling Inputs (in $M)(1,5) 2018 Other(6) $250 Adjusted O&M* $(4,625) Taxes Other Than Income (TOTI)(7) $(375) Depreciation & Amortization*(8) $(1,125) Interest Expense $(400) Effective Tax Rate 22.0% (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 reflects primarily revenues from JExel Nuclear JV, variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates, and gross receipts tax revenues (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. Other for 2018 is favorable due to NDTF realized gains that may not occur in 2019 and 2020. (7) TOTI excludes gross receipts tax of $150M (8) 2019 Depreciation & Amortization is flat to 2018 and 2020 is favorable $50M due to nuclear plant retirements 39 Q3 2018 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 40 Q3 2018 Earnings Release Slides

Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings Per Share(1) $0.32 $0.20 $0.12 $0.06 $0.16 $0.00 $0.85 Mark-to-market impact of economic hedging activities (0.05) - - - - - (0.05) Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - (0.01) - - Long-lived asset impairments 0.03 - - - - - 0.03 Plant retirements and divestitures 0.08 - - - - - 0.08 Cost management program 0.01 - - - - - 0.01 Bargain purchase gain (0.01) - - - - - (0.01) Reassessment of deferred income taxes 0.02 - - - - (0.04) (0.02) Noncontrolling interests 0.02 - - - - - 0.02 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.36 $0.19 $0.12 $0.07 $0.15 ($0.04) $0.85 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. (1) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 41 Q3 2018 Earnings Release Slides

Q3 QTD GAAP EPS Reconciliation (continued) Three Months Ended September 30, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.24 $0.20 $0.13 $0.06 $0.19 ($0.07) $0.76 Mark-to-market impact of economic hedging activities (0.07) - - - - 0.01 (0.06) Unrealized gains related to NDT fund investments (0.06) - - - - - (0.06) Long-lived asset impairments 0.01 - - - - - 0.01 Plant retirements and divestitures 0.21 - - - - - 0.21 Cost management program 0.01 - - - - - 0.01 Asset retirement obligation - - - - 0.02 - 0.02 Change in environmental liabilities (0.01) - - - - - (0.01) Reassessment of deferred income taxes (0.03) - - - (0.01) 0.02 (0.02) Noncontrolling interests 0.02 - - - - - 0.02 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.33 $0.20 $0.13 $0.07 $0.20 ($0.05) $0.88 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 42 Q3 2018 Earnings Release Slides

Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings Per Share(1) $0.52 $0.47 $0.35 $0.24 $0.38 $0.06 $2.02 Mark-to-market impact of economic hedging activities 0.10 - - - - - 0.10 Unrealized gains related to NDT fund investments (0.22) - - - - - (0.22) Amortization of commodity contract intangibles 0.03 - - - - - 0.03 Merger and integration costs 0.05 - - - (0.01) - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.15) Long-lived asset impairments 0.31 - - - - - 0.31 Plant retirements and divestitures 0.15 - - - - - 0.15 Cost management program 0.02 - - - - - 0.03 Bargain purchase gain (0.25) - - - - - (0.25) Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) Reassessment of deferred income taxes 0.02 - - - - (0.06) (0.04) Tax settlements (0.01) - - - - - (0.01) Noncontrolling interests 0.08 - - - - - 0.08 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.77 $0.50 $0.35 $0.25 $0.31 ($0.12) $2.06 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. (1) Certain immaterial prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Income have been recasted to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 43 Q3 2018 Earnings Release Slides

Q3 YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.56 $0.54 $0.35 $0.25 $0.35 ($0.13) $1.92 Mark-to-market impact of economic hedging activities 0.07 - - - - 0.01 0.08 Unrealized losses related to NDT fund investments 0.10 - - - - - 0.10 Long-lived asset impairments 0.04 - - - - - 0.04 Plant retirements and divestitures 0.44 - - - - - 0.43 Cost management program 0.02 - - - - - 0.03 Asset retirement obligation - - - - 0.02 - 0.02 Reassessment of deferred income taxes (0.03) - - - (0.01) 0.01 (0.03) Noncontrolling interests (0.04) - - - - - (0.04) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $1.16 $0.54 $0.35 $0.25 $0.36 ($0.11) $2.55 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 44 Q3 2018 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2018 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 fund investments − Impairments of certain wind projects at Generation − Certain costs related to plant retirements − Costs incurred related to a cost management program − Non-cash impacts pursuant to the annual update of asset retirement obligations − Adjustment to the remeasurement of deferred income taxes as a result of the Tax Cuts and Jobs Act (TCJA) and changes in forecasted apportionment − Generation’s noncontrolling interest, primarily related to CENG exclusion items − One-time impacts of adopting new accounting standards − Other unusual items 45 Q3 2018 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 46 Q3 2018 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 47 Q3 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy Consolidated Q3 2018 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $77 $103 $191 $1,407 $1,778 Operating Exclusions $5 $8 $24 $2 $40 Adjusted Operating Earnings $82 $111 $215 $1,409 $1,817 Average Equity $1,065 $1,434 $2,590 $13,808 $18,898 Operating ROE (Adjusted Operating Earnings/Average Equity) 7.7% 7.7% 8.3% 10.2% 9.6% Legacy Consolidated Q2 2018 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $57 $102 $189 $1,384 $1,731 Operating Exclusions $0 $8 $3 $2 $13 Adjusted Operating Earnings $57 $109 $192 $1,386 $1,744 Average Equity $1,044 $1,425 $2,577 $13,439 $18,485 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.4% 7.7% 7.4% 10.3% 9.4% Note: Items may not sum due to rounding 48 Q3 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations 2018 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $750 $1,650 $650 $1,100 $4,250 $175 $8,600 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - ($175) - ($175) Adjusted Cash Flow from Operations $750 $1,650 $650 $1,100 $3,800 $175 $8,150 2018 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $275 $550 $0 $375 ($1,050) ($100) $50 Dividends paid on common stock $200 $450 $300 $325 $1,000 ($950) $1,325 Financing Cash Flow $475 $1,000 $300 $700 ($50) ($1,050) $1,375 Exelon Total Cash Flow Reconciliation(1) 2018 GAAP Beginning Cash Balance $900 Adjustment for Cash Collateral Posted $550 Adjusted Beginning Cash Balance(3) $1,450 Net Change in Cash (GAAP)(2) $275 Adjusted Ending Cash Balance(3) $1,725 Adjustment for Cash Collateral Posted ($375) GAAP Ending Cash Balance $1,350 (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 49 Q3 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2018 2019 2020 2021 GAAP O&M $5,475 $4,925 $4,825 $4,750 Decommissioning(2) 50 50 50 50 Oyster Creek Retirement(5) (100) - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power (275) (275) (250) (250) businesses(3) O&M for managed plants that are partially owned (400) (400) (425) (425) Other (125) (50) (25) - Adjusted O&M (Non-GAAP) $4,625 $4,250 $4,175 $4,125 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Reflects earnings neutral O&M (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* (4) Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments (5) 2018 Decommissioning costs include $75M of asset retirement obligations for Oyster Creek retirement acceleration 50 Q3 2018 Earnings Release Slides