Earnings Conference Call 4th Quarter 2018 February 8, 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 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 (3) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. 2 Q4 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 Q4 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 56 of this presentation. 4 Q4 2018 Earnings Release Slides

2018 Business Priorities and Commitments ✓ Maintain industry leading operational excellence • First Quartile SAIFI performance at all utilities and First Quartile CAIDI performance at BGE, ComEd and PHI • Record nuclear output of 159 TWhs, best ever average refueling days, and capacity factor of 94.6%(1) • Exceeded power dispatch match and renewables energy capture goals ✓ Effectively deploy ~$5.4B of 2018 utility capex • Invested more than $5.5B to replace aging infrastructure and improve reliability for the benefit of customers ✓ Advance PJM power price formation changes • Awaiting decision from FERC on fast start • PJM is moving forward on scarcity pricing and reserves reforms with FERC filing expected in Q1 2019 • After assessing FERC’s fast start decision, PJM will determine path forward for full integer relaxation ✓ Prevail on legal challenges to the NY and IL ZEC programs • The Second and Seventh Circuit Court decisions upheld the legality of the NY and IL programs ✓ Seek fair compensation for at-risk plants in NJ and PA • Governor Murphy signed the NJ ZEC bill into law in May 2018 • Bicameral Nuclear Energy Caucus in PA legislature released detailed report outlining options to preserve nuclear plants including a price on carbon pollution and Governor Wolf issued an executive order establishing carbon reduction goals for PA ✓ Grow dividend at 5% rate • Increased the dividend to $1.38 from $1.31 per share ✓ Continued commitment to corporate responsibility • Exelon employees volunteered more than 240,000 hours and donated nearly $13M • Exelon Foundation donated more than $51M • Received A- from Carbon Disclosure Project – 1 of 2 U.S. utilities to do so • Named Best Company for Diversity by Forbes, Black Enterprise Magazine, DiversityInc and Human Rights Campaign 2018 GAAP Earnings of $2.07 and Adjusted Operating Earnings* of $3.12 (1) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture. Statistics represent full year 2018 results. 5 Q4 2018 Earnings Release Slides

Operating Highlights At CEG Merger (2012) 2015 YTD 2018 Operations Metric BGE ComEd PECO PHI BGE ComEd PECO PHI OSHA Recordable Rate Electric 2.5 Beta SAIFI (Outage Operations Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Satisfaction N/A Customer Service Level % of Calls Operations Answered in <30 sec Abandon Rate Percent of Calls Responded to No Gas No Gas Gas Operations in <1 Hour Operations Operations Electric Utility Panel of 24 rd nd nd th Performance Overall Rank (1) 23 2 2 18 Utilities Quartiles • Reliability performance remains strong across all utilities and safety performance continues to improve: o ComEd achieved top decile performance and PHI matched its best on record results in SAIFI o For CAIDI, BGE and ComEd achieved top decile performance • Top decile Gas odor response for the 6th consecutive year for BGE and PECO and 2nd consecutive year for PHI • ComEd and PHI scored in the top decile for service level with BGE and PHI achieving best on record performances • ComEd, BGE, and PHI had best on record performances in Call Center Satisfaction (1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer 6 Q4 2018 Earnings Release Slides

Best in Class at ExGen and Constellation Exelon Generation Operational Metrics Constellation Metrics • Continued best in class performance across (1) 78% retail power our Nuclear fleet: 30% power new customer renewal customer win rate − Capacity factor for Exelon (owned and rate operated units) was 94.6%(2) − This was the third consecutive year more than 94% and the fifth out of the last six 92% natural gas 25 month average years topping 94%(2) customer power contract retention rate term − Most nuclear power ever generated at 159 TWhs(2) − 2018 average refueling outage duration of Average customer 21 days, a new Exelon record Stable Retail duration of more Margins • Strong performance across our Fossil and than 6 years Renewable fleet: − Renewables energy capture: 96.1% − Power dispatch match: 98.1% Note: Statistics represent full year 2018 results (1) Excludes Salem (2) Excludes EDF’s equity ownership share of the CENG Joint Venture 7 Q4 2018 Earnings Release Slides

2018 Financial Results Q4 2018 EPS Results Full Year 2018 EPS Results $3.12 • Adjusted (non-GAAP) operating earnings $0.58 drivers versus full year guidance: $0.23 $1.39 Exelon Utilities $0.16 $2.07 – Favorable weather $0.07 $0.07 $0.38 – Higher distribution and $0.13 $0.13 $0.32 $0.33 transmission revenues $0.06 $0.07 $0.47 $0.48 – ComEd ROE $0.15 $0.15 – Storm costs $0.41 $0.43 ($0.07) ($0.18) $0.69 $0.69 Exelon Generation ($0.07) – NDT realized gains(1) ($0.18) Q4 GAAP Q4 Adjusted ($0.20) – Higher allocated transmission Earnings Operating FY GAAP FY Adjusted costs Earnings* Earnings Operating Earnings* ExGen PECO ComEd BGE PHI HoldCo Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites 8 Q4 2018 Earnings Release Slides

Exelon Utilities’ 2018 Distribution Rate Case Results August 2018 December 2018 February 2018 Pepco Electric DC ComEd (8/9/2018) (12/4/2018) Delmarva MD Delmarva Electric DE PECO Electric (2/9/2018) (8/21/2018) (12/20/2018) May 2018 November 2018 January 2019 Pepco Electric MD Delmarva Gas DE BGE Gas (5/31/2018) (11/8/2018) (1/4/2019) • Returned more than $675M of annual savings from tax reform to our 10 million customers • 8 electric and gas distribution final orders across the utilities of which 6 were constructive settlements with key intervenors during the year 9 Q4 2018 Earnings Release Slides

Trailing Twelve Month Earned ROEs* vs Allowed ROE Trailing Twelve Month Earned ROEs* Allowed ROE Q4 2017 TTM Earned ROE Q4 2018 TTM Earned ROE 9.9% 9.9% 9.7% 10.3% 10.1% 9.7% 9.5% 8.8% 8.7% 8.1% 7.7% 7.0% 5.6% ACE Delmarva Pepco Legacy Exelon Consolidated Utilities Exelon Utilities Note: Represents the twelve-month periods ending December 31, 2017 and December 31, 2018, respectively. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution and Electric Transmission). 10 Q4 2018 Earnings Release Slides

Our Capital Plan Drives Leading Rate Base Growth Capital Expenditures ($M) Rate Base ($B)(1) 5,925 5,750 5,875 50.7 5,325 950 +7.8% 1,250 1,075 47.3 44.2 8.7 1,100 41.2 8.1 975 7.7 1,000 975 37.6 6.9 9.7 975 6.3 9.1 8.4 1,550 7.9 1,550 7.1 1,525 13.1 1,375 12.1 11.4 10.8 10.0 2,425 2,150 2,175 19.2 1,875 16.7 18.0 14.2 15.6 2019E 2020E 2021E 2022E 2018E 2019E 2020E 2021E 2022E BGE PECO PHI ComEd ~$23B of capital will be invested at Exelon utilities from 2019–2022 for grid modernization and resiliency for the benefit of our customers Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding (1) Rate base reflects year-end estimates 11 Q4 2018 Earnings Release Slides

Exelon Utilities EPS* Growth of 6-8% to 2022 Exelon Utilities Operating Earnings* $2.50 $2.45 $2.40 $2.30 $2.25 $2.20 $2.15 $2.15 $2.10 $2.05 $2.00 $1.90 $1.95 $1.80 $1.85 $1.80 $1.75 $1.70 $1.74 $1.60 $1.50 Utility Adjusted Operating Operating Earnings* Adjusted Utility $1.50 $0.00 2018A 2019E 2020E 2021E 2022E Rate base growth combined with positive regulatory outcomes drive EPS growth Note: Includes after-tax interest expense held at Corporate for debt associated with existing utility investment 12 Q4 2018 Earnings Release Slides

Exelon Generation: Gross Margin Update Change from December 31, 2018 September 30, 2018 Gross Margin Category ($M)(1) 2019 2020 2021 2019 2020 Open Gross Margin(2,5) $4,350 $4,050 $3,750 $50 $150 (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) $250 $250 $100 - - Power New Business / To Go $500 $700 $900 $(50) $(100) Non-Power Margins Executed $200 $150 $150 - - Non-Power New Business / To Go $300 $350 $400 - - Total Gross Margin*(4,5) $7,650 $7,400 $7,150 - $50 Recent Developments • In October 2018 we acquired the Everett LNG import facility and in December, we received the cost of service order from FERC for Mystic, which together will allow us to provide fuel security to the New England market into May 2024 • In January 2019 the Texas PUCT approved modifications to the ORDC curve, which are not reflected in the numbers above • Behind ratable hedging position reflects the upside we see in power prices ― ~9-12% behind ratable in 2019 when considering cross commodity hedges ― ~8-11% behind ratable in 2020 when considering cross commodity hedges (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2018 market conditions (5) Reflects TMI retirement by September 2019 13 Q4 2018 Earnings Release Slides

Driving Costs and Capital Out of the Generation Business Adjusted O&M* ($M)(1) Capital Expenditures ($M)(1,2,3) 1,900 1,925 -1.0% 4,325 150 4,250 4,200 4,200 200 1,750 150 1,525 125 900 900 775 625 875 825 825 775 2019E 2020E 2021E 2022E 2019E 2020E 2021E 2022E Committed Growth Nuclear Fuel Base Cost optimization programs and planned nuclear plant closures drive lower total costs Note: All amounts rounded to the nearest $25M and numbers may not add due to rounding (1) O&M and Capital Expenditures reflect retirement of TMI in 2019 (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) 2019E growth capital expenditures reflects a ~$75M shift of cash outlay from 2018A to 2019E related to West Medway and Retail Solar 14 Q4 2018 Earnings Release Slides

ExGen’s Strong Available Cash Flow* Supports Utility Growth and Debt Reduction 2019-2022 Exelon Generation Available Cash*(1) and Uses of Cash ($B) ~$7.8 ~($0.6) ($4.0-$4.4) ($0.3-$0.5) ($2.2-$2.8) ExGen Cumulative Committed ExGen Utility Investment External Dividend Debt Reduction Available Cash* Growth CapEx 2019E-2022E(1) Redeploying Exelon Generation’s Available Cash Flow* to maximize shareholder value (1) Cumulative Available Cash is a midpoint of a range based on December 31, 2018 market prices. Sources include ~$0.4B of use of available cash in hand, EDF cash distributions, change in margin, tax sharing agreement, equity investments, equity distributions for renewables JV and Bluestem tax equity, acquisitions and divestitures. 15 Q4 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% 4.0 20% 18%-20% 20% 3.0x 3.0 15% 2.4x S&P Threshold 2.0 1.9x 10% Book Excluding Non-Recourse 5% 1.0 0% 0.0 2019 Target 2019 Target Credit Ratings by Operating Company Current Ratings (2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3(3) A2 A2 S&P BBB-(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 February 8, 2019, 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 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 Q4 2018 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, absence of NDT gains and 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 transmission revenue, return to $0.30 - $0.40 $0.33 normal storm (historical average), partially offset by higher depreciation $0.45 - $0.55 and a return to normal weather $0.48 • PHI: Higher distribution and transmission revenue and favorable $0.45 - $0.55 $0.43 O&M, partially offset by higher depreciation • ComEd: Increased capital $0.69 investments to improve reliability in $0.70 - $0.80 distribution and transmission ($0.18) ($0.20) 2018 Actuals 2019 Guidance Expect Q1 2019 Adjusted Operating Earnings* of $0.80 - $0.90 per share 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 17 Q4 2018 Earnings Release Slides

2019 Business Priorities and Commitments Maintain industry leading operational excellence Meet or exceed our financial commitments Effectively deploy ~$5.3B of utility capex Advocate for policies to enable the utility of the future Advance PJM energy market price formation reforms Preserve authority of states to enact state clean energy policies and seek fair compensation for zero-emitting nuclear plants Grow dividend at 5% rate Continued commitment to corporate responsibility 18 Q4 2018 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 19 Q4 2018 Earnings Release Slides

Additional Disclosures 20 Q4 2018 Earnings Release Slides

Exelon Utilities EPS Growth of 6-8% to 2022 Q4 2017 Operating Earnings* Q4 2018 Operating Earnings* $2.50 $2.50 $2.45 $2.40 $2.40 $2.30 $2.30 $2.25 $2.20 $2.20 $2.20 $2.10 $2.15 $2.10 $2.15 $2.00 $2.10 $2.05 $2.00 $2.00 $1.90 $1.90 $1.95 $1.80 $1.90 $1.80 $1.80 $1.80 $1.85 $1.70 $1.70 $1.75 $1.70 $1.60 $1.74 $1.57 $1.60 $1.50 $1.50 $1.40 $1.50 $0.00 $0.00 2017A 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Utility growth rate remains 6-8%, driven by rate base growth and positive regulatory outcomes Note: Includes after-tax interest expense held at Corporate for debt costs associated with utility investment. 21 Q4 2018 Earnings Release Slides

Utility Capex and Rate Base vs. Previous Disclosure Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) Gas Delivery Electric Transmission Electric Distribution 5,925 5,750 5,875 5,400 5,525 5,100 5,225 5,150 5,325 800 700 675 675 775 750 725 700 725 1,075 1,100 1,100 1,275 1,100 1,050 1,125 1,125 950 3,850 3,875 4,125 3,625 3,325 3,375 3,300 3,750 3,675 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +7.8% +7.4% 50.7 46.0 47.3 43.5 44.2 6.8 40.7 41.2 6.3 37.8 5.5 6.2 37.6 5.5 34.6 4.8 4.9 10.3 4.1 9.7 4.2 9.6 3.4 9.3 8.8 9.2 8.3 8.8 7.7 8.2 33.5 28.7 30.1 29.5 31.4 23.4 25.4 27.1 25.2 27.6 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E We will invest $22.9B of capital in utilities from 2019-2022, supporting rate base growth of 7.8% from 2018-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 22 Q4 2018 Earnings Release Slides

ComEd Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 2,425 2,150 2,150 2,175 2,125 425 1,850 1,850 1,875 325 375 1,725 400 450 350 300 325 375 2,000 1,750 1,775 1,725 1,875 1,400 1,500 1,475 1,575 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +7.5% +7.8% 19.2 17.4 18.0 16.6 16.7 1.1 14.5 15.6 15.6 1.0 13.1 0.8 1.0 14.2 0.8 4.0 0.6 4.0 0.6 4.0 0.1 0.3 3.7 3.9 0.4 3.7 3.8 3.4 3.6 3.5 12.4 12.1 13.0 14.1 9.5 10.5 11.3 11.9 10.3 11.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Other(1) Electric Transmission Electric Distribution ~$8.6B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program 23 Q4 2018 Earnings Release Slides

PECO Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 850 975 1,000 800 825 825 975 975 850 275 250 300 250 225 275 250 300 225 125 50 100 125 50 125 75 75 100 600 600 650 450 475 450 475 500 575 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.2% +6.9% 9.7 8.6 9.1 8.0 7.9 8.4 7.1 7.6 7.1 2.3 2.5 6.6 2.0 2.3 1.9 2.1 1.7 1.9 1.7 1.1 1.1 1.5 1.1 1.1 1.0 1.1 0.9 0.9 1.0 1.0 5.6 6.0 4.2 4.5 4.7 5.0 5.3 4.4 5.0 5.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$3.9B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 24 Q4 2018 Earnings Release Slides

BGE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 1,250 1,100 1,100 1,050 1,025 1,075 1,000 1,000 450 950 425 400 425 375 425 400 400 375 275 225 200 200 225 175 200 225 175 525 400 475 450 375 450 475 400 400 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.3% +9.0% 8.7 7.7 8.1 7.6 8.0 6.9 6.3 2.7 6.4 6.9 2.3 2.5 5.7 2.3 2.5 2.0 2.0 1.7 1.7 1.5 1.7 1.4 1.5 1.3 1.5 1.5 1.1 1.3 1.0 1.2 4.0 4.1 4.3 3.2 3.4 3.7 3.9 4.0 3.4 3.7 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$4.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 25 Q4 2018 Earnings Release Slides

PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 1,550 1,550 1,500 1,500 1,500 1,500 1,525 1,400 1,375 50 50 50 50 50 75 75 50 50 425 400 425 475 425 375 475 475 300 1,025 975 975 950 1,050 1,025 1,025 1,000 1,075 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +6.8% +7.0% 13.1 11.3 12.0 12.1 10.6 0.5 10.8 11.4 0.5 9.2 9.9 0.4 10.0 0.5 0.4 0.4 3.2 0.4 0.4 3.4 0.3 2.9 3.0 0.3 2.9 3.0 2.4 2.6 2.6 2.8 8.3 8.7 9.2 6.5 7.0 7.4 7.9 7.1 7.6 8.1 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$6.0B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 26 Q4 2018 Earnings Release Slides

ACE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 375 400 350 325 300 300 325 150 175 150 250 125 125 225 150 150 75 100 200 200 200 225 200 150 175 175 150 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.0% 2.7 2.8 +7.7% 2.5 2.2 2.9 3.0 2.1 1.0 1.1 2.6 0.9 2.5 0.8 2.3 1.1 0.8 1.0 1.0 0.8 0.9 1.5 1.6 1.7 1.8 1.3 1.5 1.6 1.7 1.8 1.9 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Electric Transmission Electric Distribution ~$1.2B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 27 Q4 2018 Earnings Release Slides

Delmarva Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 400 375 400 50 350 325 75 325 50 325 350 325 50 50 50 50 50 150 75 150 100 125 100 100 100 100 75 200 200 200 200 200 175 175 175 175 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +5.6% +4.4% 3.5 3.2 3.3 3.2 3.3 3.1 2.9 3.1 0.5 2.9 0.5 0.4 0.5 2.7 0.4 0.4 0.3 0.4 0.4 1.0 0.3 1.0 1.0 1.0 1.0 1.0 1.0 0.9 0.8 0.9 1.7 1.8 1.9 1.9 1.5 1.6 1.7 1.7 1.8 1.6 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Gas Delivery Electric Transmission Electric Distribution ~$1.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 28 Q4 2018 Earnings Release Slides

Pepco Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) Q4 2018 Capital Expenditures ($M) 950 950 850 900 800 225 725 750 300 725 725 250 175 250 125 150 100 75 750 600 575 600 625 625 650 625 625 2018E 2019E 2020E 2021E 2018A 2019E 2020E 2021E 2022E Q4 2017 Rate Base ($B) Q4 2018 Rate Base ($B) +8.1% +6.9% 6.6 5.8 5.9 5.4 5.3 5.6 1.2 5.1 4.9 4.4 4.7 1.0 0.9 0.9 0.9 0.9 0.9 0.8 0.9 0.9 5.4 4.5 4.8 4.6 5.0 3.6 3.9 4.2 4.0 4.3 2017E 2018E 2019E 2020E 2021E 2018E 2019E 2020E 2021E 2022E Electric Transmission Electric Distribution ~$3.4B of Capital being invested from 2019-2022 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 29 Q4 2018 Earnings Release Slides

Mechanisms Cover Bulk of Rate Base Growth Rate Base Growth Breakout 2019–2022 ($B) 3.5 13.1 Base Rate Case 1.1 Tracker/Formula Rate 2.4 4.8 3.0 1.2 1.9 3.0 1.1 1.9 3.6 8.3 1.4 2.1 2019E 2020E 2021E 2022E Total Of the ~$13.1B of rate base growth Exelon Utilities forecasts over the next 4 years, ~63% will be recovered through existing formula and tracker mechanisms Note: Numbers may not add due to rounding 30 Q4 2018 Earnings Release Slides

Exelon Utilities Trailing Twelve Month Earned ROEs* Q4 2018: Trailing Twelve Month Earned ROEs* 12.0% Legacy Exelon Utilities Consolidated Exelon Utilities 11.0% 10.0% Delmarva $2.9/8.8% 9.0% $27.6/10.1% 8.0% Pepco $37.6/9.7% $4.9/8.7% 7.0% ACE 6.0% $2.3/7.0% 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 December 31, 2018. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Size of bubble based on rate base. 31 Q4 2018 Earnings Release Slides

ExGen O&M and Capex vs. Previous Disclosure Adjusted O&M* - Q3 2018 ($M)(1) Adjusted O&M* - Q4 2018 ($M)(1) -3.7% -1.0% 4,625 4,250 4,175 4,125 4,325 4,250 4,200 4,200 2018E 2019E 2020E 2021E 2019E 2020E 2021E 2022E CapEx – Q4 2017 ($M)(1,2) CapEx – Q4 2018 ($M)(1,2,3) 2,275 375 1,850 1,825 1,825 75 1,900 1,925 125 175 1,750 150 200 950 150 1,525 900 825 800 125 900 900 775 625 950 875 875 850 875 825 825 775 2018E 2019E 2020E 2021E 2019E 2020E 2021E 2022E Committed Growth Nuclear Fuel Base (1) O&M and CapEx reflect retirement of TMI in 2019 (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) 2019E growth capital expenditures reflects a ~$75M shift of cash outlay from 2018A to 2019E related to West Medway and Retail Solar 32 Q4 2018 Earnings Release Slides

Adjusted O&M* Forecast • Expect Compound Annual Growth Rate of -0.3% for 2019–2022 ($ in millions) 8,300 7,975 $775 $750 $825 $800 Key Year-over-Year Drivers $1,025 • BGE: Return to normal storm (historical average) $1,000 • PECO: Return to normal storm (historical $1,300 average) • PHI: Decrease driven by reductions for $1,225 one-time items in 2018 and ongoing cost reduction efforts in 2019 • ComEd: Primarily driven by lower mutual assistance support • ExGen: Cost management initiative, lower planned outages, and impact of $4,600 nuclear retirements, partly offset by $4,325 Everett Marine Terminal -$200 -$150 2018 Actuals(1) BGE PHI ExGen 2019 Guidance(1) PECO ComEd HoldCo (1) All amounts rounded to the nearest $25M and may not add due to rounding 33 Q4 2018 Earnings Release Slides

2019 Projected Sources and Uses of Cash Total Exelon Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(8) Utilities 2019E Balance Beginning Cash Balance*(2) 1,825 (1) All amounts rounded to the nearest Adjusted Cash Flow from Operations*(2) 700 1,425 850 1,125 4,075 4,025 (225) 7,875 $25M. Figures may not add due to rounding. (3) - - - - - (1,800) (50) (1,850) Base CapEx and Nuclear Fuel (2) Gross of posted counterparty Free Cash Flow* 700 1,425 850 1,125 4,075 2,250 (275) 6,050 collateral Debt Issuances 300 700 300 375 1,675 - - 1,675 (3) Figures reflect cash CapEx and CENG Debt Retirements - (300) - - (300) (625) - (925) fleet at 100% Project Financing n/a n/a n/a n/a n/a (125) n/a (125) (4) Other Financing primarily includes Equity Issuance/Share Buyback - - - - - - - - expected changes in money pool, tax sharing from the parent, renewable Contribution from Parent 200 250 150 200 800 - (800) - JV distributions, tax equity cash flows, Other Financing(4) 175 200 25 (100) 325 (125) 25 200 EDF Tax distributions and capital leases Financing*(5) 675 850 475 475 2,475 (875) (775) 825 (5) Financing cash flow excludes Total Free Cash Flow and Financing 1,375 2,275 1,325 1,600 6,575 1,350 (1,075) 6,850 intercompany dividends Utility Investment (1,100) (1,875) (975) (1,375) (5,325) - - (5,325) (3,6) (6) ExGen Growth CapEx primarily ExGen Growth - - - - - (150) - (150) includes Retail Solar and W. Medway Acquisitions and Divestitures - - - - - - - - (7) Dividends are subject to declaration Equity Investments - - - - - (25) - (25) by the Board of Directors Dividend(7) - - - - - - - (1,400) (8) Includes cash flow activity from Other CapEx and Dividend (1,100) (1,875) (975) (1,375) (5,325) (175) - (6,925) Holding Company, eliminations, and other corporate entities Total Cash Flow 250 400 350 225 1,225 1,175 (1,075) (50) Ending Cash Balance*(2) 1,775 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*, ✓ $1.4B of long-term debt at the utilities, net Investing $5.5B of growth capex, with including $2.3B at ExGen and $4.1B at the of refinancing, to support continued growth $5.3B at the Utilities and $0.2B at ExGen Utilities and retirement of $0.6B of ExGen debt Note: Numbers may not add due to rounding 34 Q4 2018 Earnings Release Slides

Exelon Debt Maturity Profile(1) As of 12/31/18 (1,2) ($M) LT Debt Balances (as of 12/31/18) BGE 2.9B 500 ComEd 8.3B PECO 3.3B PHI 6.3B ExGen recourse 6.7B ExGen non-recourse 2.1B HoldCo 6.3B 910 Consolidated 35.8B 2,512 1,023 1,225 850 500 600 700 1,189 175 1,850 312 1,430 1,400 1,150 997 900 900 975 800 833 807 750 763 833 788 741 750 623 185 675 700 650 360 300 258 295 350 53 78 2019 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 PHI HoldCo EXC Regulated ExGen ExCorp Exelon’s weighted average LTD maturity is approximately 13 years (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect 2018 10-K GAAP financials; ExGen debt includes legacy CEG debt 35 Q4 2018 Earnings Release Slides

EPS Sensitivities* 2019E 2020E 2021E Henry Hub Natural Gas + $1/MMBtu $0.10 $0.29 $0.44 (1) - $1/MMBtu ($0.08) ($0.26) ($0.41) NiHub ATC Energy Price + $5/MWh $0.03 $0.17 $0.26 - $5/MWh ($0.03) ($0.17) ($0.26) ExGen EPS Impact*EPS ExGen PJM-W ATC Energy Price + $5/MWh ($0.00) $0.06 $0.12 - $5/MWh $0.01 ($0.05) ($0.11) ComEd ROE $0.03 $0.03 $0.03 Pension Expense $0.02 $0.02 $0.01 InterestRate Cost of Debt ($0.00) ($0.01) ($0.01) Sensitivity to+50 Sensitivity BP Share count (millions) 973 977 981 Exelon Consolidated Effective Tax Rate 17% 18% 17% ExGen Effective Tax Rate 21% 23% 22% Exelon Consolidated Cash Tax Rate 1% 5% 4% (1) Based on December 31, 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 EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are also considered. 36 Q4 2018 Earnings Release Slides

Historical Nuclear Capital Investment Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Baseline CAGR Cancelled Growth Fukushima Growth(4) Nuclear Baseline (excluding Fuel) (2,3) 1,000 975 -1.2% 925 50 50 825 850 150 775 250 25 325 175 650 25 675 175 175 50 25 25 600 600 50 100 75 550 550 650 700 675 625 575 575 600 550 600 600 550 550 2011 2012 2013 2014 2015 2016 2017 2018 2019E 2020E 2021E 2022E Nuclear Capacity Factor(5,6) Significant historical investments have mitigated asset management issues and prepared sites for Industry Average Exelon license extensions already received, reducing future capital needs. In addition, internal cost 94.1% 94.3% 94.6% 94.1% 94.6% 93.3% 92.7% 93.7% initiatives have found more cost efficient solutions to large CapEx spend, such as leveraging reverse engineering replacements 89.3% 89.2% 90.0% 90.0% 89.2% rather than large system wide modifications, 85.3% 84.6% resulting in baseline CAGR of -1.2%, even with net addition of 2 sites. 2011 2012 2013 2014 2015 2016 2017 2018 (1) Reflects accrual capital expenditures with CENG at 50% ownership. Assumes TMI retirement in September 2019. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Includes CENG beginning in April 2014 and FitzPatrick beginning in April of 2017, excludes Salem and Fort Calhoun (6) Industry average is for major operators excluding Exelon and includes 3 months of Fitzpatrick prior to Exelon acquisition. 2018 industry average (excluding Exelon) was not available at the time of publication. 37 Q4 2018 Earnings Release Slides

Exelon Recognition and Partnerships SUSTAINABILITYSustainability DIVERSITYDiversity& INCLUSION and Inclusion Dow Jones Sustainability Index HeforShe Exelon named to Dow Jones Sustainability Index for 13th consecutive Exelon joined U.N. Women’s HeForShe campaign, which is focused on year. gender equality. Pledge includes a $3 million commitment to develop new STEM programs for girls and young women and improve the Newsweek Magazine’s Green Rankings retention of women at Exelon by 2020. The Newsweek Green Rankings evaluate corporate sustainability and environmental performance. Exelon ranked in the top three among Billion Dollar Roundtable utilities, No. 12 on the U.S. 500 and No. 24 on the Global 500 list Exelon became the first energy company to join the Billion Dollar among the world's largest publicly traded companies. Roundtable, an organization that promotes supplier diversity for corporations achieving $1 billion or more in annual direct spending Land for People Award 2017 with minority and women-owned businesses. Received the Trust for Public Land’s national “Land for People Award” CEO Action for Diversity & Inclusion in recognition of Exelon’s deep support of environmental stewardship, Exelon joined 150 leading companies for the CEO Action for Diversity creating new parks and promoting conservation. & Inclusion™ , the largest CEO-driven commitment aimed at taking action to cultivate a workplace where diverse perspectives and experiences are welcomed and respected. Community Engagement Workforce $52.1 million DiversityInc Top 50 Companies 2018 Last year, Exelon and its employees set all-time records, committing Exelon ranked No. 32 on DiversityInc's list of Top 50 companies for more than $52.1 million to non-profit organizations and volunteering diversity and 4th for the top 18 companies in hiring for veterans. more than 210,000 hours. Points of Light, “The Civic 50” 2017 Indeed.com “50 Best Places to Work” 2017 Exelon was named for the first time to the Civic 50, recognizing the Indeed.com ranked Exelon No. 18 on its “50 Best Places to Work.” most community-minded companies by Points of Light, the world’s largest organization dedicated to volunteer service. Human Rights Campaign “Best Places to Work” 2011-2018 2017 Laurie D. Zelon Pro Bono Award Exelon earned the designation of “Best Place to Work” on HRC’s Exelon’s legal department was honored by the Pro Bono Institute (PBI) Corporate Equality Index for a seventh consecutive year in 2018, with the 2017 Laurie D. Zelon Pro Bono Award. receiving a perfect score of 100. The Military Times Best for Vets 2013-2018 Kids in Need of Defense Innovation Award For the sixth year in a row, Exelon received this recognition for its Exelon's legal department and the Baltimore chapter of Organization commitment to providing opportunities to America's veterans. of Latinos at Exelon (OLE) for their work with unaccompanied minors from Central America. Historically Black Engineering Schools 2013-2017 Exelon was recognized as a top corporate supporter of the nation’s historically black engineering programs. 38 Q4 2018 Earnings Release Slides

Climate Leadership Council - Founding Members Exelon is a founding member of the Climate Leadership Council (CLC) – an effort to promote a carbon fee-and-dividend program. The Four Pillars of a Carbon Dividends Plan: • Gradually Increasing Carbon Tax: Fee would be applied at the point where fossil fuels enter the economy (i.e. wellhead, mine, refinery or port), start at $40/ton and increase 5% a year (the increase could be 10% for years when emissions fail to fall aggressively enough) • Carbon Dividends: Americans would receive a monthly dividend check - ~$2,000/year to begin, gradually increasing over time as revenue increases; 70% of Americans would be net beneficiaries • Border Carbon Adjustments: Imports and exports would be subject to a border adjustment • Significant Regulatory Rollback: Much of EPA’s regulatory authority over greenhouse gases would be phased out. Carbon emitters would be protected against federal and state tort liability suit to the extent emissions are covered (e.g., carbon but not methane) 39 Q4 2018 Earnings Release Slides

Exelon Utilities 40 Q4 2018 Earnings Release Slides

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep ROE / Requirement Order Equity Ratio (1,6) 8.69% / ComEd FO ($24.1M) Dec 4, 2018 47.11% Delmarva (1,2) 9.70% / FO ($3.5M) Nov 8, 2018 Gas (DE) 50.52% PECO (1,3,7) FO $24.9M N/A Dec 20, 2018 Electric BGE (4) 9.80% / RT EH IB RB FO $64.9M (4) Jan 4, 2019 Gas 52.85% (1) 10.10% / ACE(5) $121.9M Q3 2019 IT RT EH EH EH FO 50.22% Pepco MD (1) 10.30% / $30.0M Aug 13, 2019 Electric CF FO 50.50% 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, and New Jersey Board of Public Utilities 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) 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. DPSC is expected to issue the second Final Order by the end of Q1 2019 regarding recovery of costs related to Interface Management Unit (IMU) Battery Replacement. (3) On December 20, 2018, the PaPUC voted 5-0 to approve a settlement agreement in PECO’s 2018 electric distribution rate case that will go into effect on January 1, 2019. The black box approval does not stipulate any ROE, Equity Ratio and Rate Base. (4) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (5) ACE plans to put interim rates in effect nine months after the filing date, subject to refund, as allowed by the regulations. (6) Original filing amount was ($22.9M). Recent discovery period removed additional ($1.2M) of revenue requirement to limit issues in the proceeding. (7) Reflects a $96M revenue requirement increase less $71M of 2019 TCJA related tax benefits 41 Q4 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 9 months actual and 3 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: 7.35% • 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 $121.9M • Interim rates expected to go in effect in May 2019, Residential Total Bill % Increase 10.8% 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 Sep Filed rate case 8/21/2018 Intervenor testimony 2/5/2019 Rebuttal testimony 3/14/2019 Evidentiary hearings 04/23/2019 - 06/04/2019 Initial briefs due Reply briefs due 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) ACE plans to put interim rates in effect nine months after the filing date, subject to refund, as allowed by the regulations 42 Q4 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 Common Equity Ratio 52.85%(1) STRIDE surcharge into base rates • The Commission issued its order on this case on (1) Rate of Return ROE: 9.80%; ROR: 7.09% January 4, 2019 Rate Base (Adjusted) $1.6B Revenue Requirement Increase $64.9M(1) Residential Total Bill % Increase ~2.4%(2) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 06/08/2018 Intervenor testimony 09/14/2018 Rebuttal testimony 10/12/2018 Evidentiary hearings 11/2/2018 – 11/16/2018 Initial briefs due 11/2018 Reply briefs due 12/2018 Commission order 01/04/2019 (1) Reflects $43.2M increase and $21.7M STRIDE reset. Test year updated for May-July 2018 actuals and reflects long-term debt issuance made in September 2018. (2) Increase expressed as a percentage of a combined electric and gas residential customer total bill 43 Q4 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 Common Equity Ratio 47.11% from federal tax reform, partially offset by Rate of Return ROE: 8.69%; ROR: 6.52% continued investment in the electric grid, state tax rate increase, elimination of bonus Rate Base (Adjusted) $10,675M depreciation and weather/economic impacts 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 9/11/208 Reply briefs 9/25/2018 Commission order 12/4/2018 (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. 44 Q4 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 the Delaware Public Service Test Year January 1, 2017 – December 31, 2017 Commission (DPSC) seeking an increase in gas distribution base rates Test Period 8 months actual and 4 months estimated • September 7, 2018, Delmarva Power filed a Common Equity Ratio 50.52%(2) partial gas Settlement Agreement and requested a decrease in revenue requirement of ($3.5M)(2) (2) Rate of Return ROE: 9.70%; ROR: 6.78% • The partial Settlement Agreement resolves all issues except a $3.5M regulatory asset related to Rate Base (Adjusted) N/A the Interface Management Unit (IMU) batteries Revenue Requirement Decrease ($3.5M)(1,2) • November 8, 2018, DPSC approved settlement • DPSC expected to issue second Final Order by end Residential Total Bill % Decrease (2) (2.6%) of Q1 2019 regarding recovery of costs related to IMU Battery Replacement 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 11/8/2018 (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. 45 Q4 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 December 20, 2018, the PaPUC voted 5-0 to Test Period 12 Months Budget (Fully projected future test year) approve a settlement agreement in PECO’s 2018 electric distribution rate case that went into effect Common Equity Ratio N/A on January 1, 2019. The black box approval does not stipulate any ROE, Equity Ratio or Rate Base. Rate of Return ROE: N/A; ROR: N/A • The approval amount of $96M(2) represents 63% of Rate Base N/A the $153M ask. This is in line with prior PA electric distribution rate case outcomes. Revenue Requirement Increase $24.9M(1,2) Residential Total Bill % Increase 1.2% 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 9/07/2018 Reply briefs 9/17/2018 Commission order 12/20/2018 (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 a $96M revenue requirement increase less $71M of 2019 TCJA related tax benefits 46 Q4 2018 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 8 months actual and 4 months estimated electric distribution base rates • Size of ask is driven by continued investments Requested Common Equity Ratio 50.50% in electric distribution system to maintain and Requested Rate of Return ROE: 10.30%; ROR: 7.81% increase reliability and customer service • Forward looking reliability plant additions Proposed Rate Base (Adjusted) $2.0B through July 2019 ($6.6M of Revenue Requirement based on 10.30% ROE) included Requested Revenue Requirement Increase $30.0M in revenue requirement request Residential Total Bill % Increase 2.76% Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Filed rate case 1/15/2019 Intervenor testimony Rebuttal testimony Evidentiary hearings Commission order expected 8/13/2019 47 Q4 2018 Earnings Release Slides

Exelon Generation Disclosures December 31, 2018 48 Q4 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 49 Q4 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 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 50 Q4 2018 Earnings Release Slides

ExGen Disclosures December 31, 2018 Gross Margin Category ($M)(1) 2019 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)(2,5) $4,350 $4,050 $3,750 Capacity and ZEC Revenues(2,5) $2,050 $1,900 $1,850 Mark-to-Market of Hedges(2,3) $250 $250 $100 Power New Business / To Go $500 $700 $900 Non-Power Margins Executed $200 $150 $150 Non-Power New Business / To Go $300 $350 $400 Total Gross Margin*(4,5) $7,650 $7,400 $7,150 Reference Prices(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.85 $2.67 $2.61 Midwest: NiHub ATC prices ($/MWh) $26.60 $25.12 $24.26 Mid-Atlantic: PJM-W ATC prices ($/MWh) $33.42 $32.45 $30.84 ERCOT-N ATC Spark Spread ($/MWh) $13.29 $9.71 $7.60 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $32.46 $30.69 $31.31 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2018 market conditions (5) Reflects TMI retirement by September 2019 51 Q4 2018 Earnings Release Slides

ExGen Disclosures December 31, 2018 Generation and Hedges 2019 2020 2021 Exp. Gen (GWh)(1) 193,200 185,100 180,700 Midwest 96,900 96,400 95,300 Mid-Atlantic(2,6) 54,000 48,500 48,700 ERCOT 25,700 24,500 20,100 New York(2) 16,600 15,700 16,600 % of Expected Generation Hedged(3) 89%-92% 56%-59% 32%-35% Midwest 86%-89% 51%-54% 29%-32% Mid-Atlantic(2,6) 96%-99% 68%-71% 40%-43% ERCOT 76%-79% 44%-47% 22%-25% New York(2) 101%-104% 66%-69% 40%-43% Effective Realized Energy Price ($/MWh)(4) Midwest $28.50 $28.00 $28.50 Mid-Atlantic(2,6) $39.00 $37.00 $32.50 ERCOT(5) $2.00 $1.00 $1.50 New York(2) $34.50 $34.00 $30.00 (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2019, 14 in 2020, and 13 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.5%, 93.9%, and 94.1% in 2019, 2020, and 2021, respectively at Exelon- operated nuclear plants, at ownership. These estimates of expected generation in 2019, 2020 and 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin in order to determine the mark- to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT (6) Reflects TMI retirement by September 2019 52 Q4 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Sensitivities December 31, 2018 Gross Margin* Sensitivities (with existing hedges)(1) 2019 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $135 $385 $580 - $1/MMBtu $(105) $(340) $(540) NiHub ATC Energy Price + $5/MWh $45 $225 $345 - $5/MWh $(45) $(220) $(345) PJM-W ATC Energy Price + $5/MWh $(5) $75 $155 - $5/MWh $10 $(70) $(150) NYPP Zone A ATC Energy Price + $5/MWh $(10) $25 $50 - $5/MWh $10 $(25) $(50) Nuclear Capacity Factor +/- 1% +/- $35 +/- $35 +/- $30 (1) Based on December 31, 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 53 Q4 2018 Earnings Release Slides

ExGen Hedged Gross Margin* Upside/Risk 9,000 8,500 (1) $8,100 8,000 $7,950 $7,800 7,500 $7,400 7,000 $7,000 Approximate Gross ($ Margin* million) Gross Approximate 6,500 $6,550 6,000 2019 2020 2021 (1) Represents an approximate range of expected gross margin, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin in 2019, 2020 and 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of December 31, 2018. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects TMI retirement by September 2019. 54 Q4 2018 Earnings Release Slides

Illustrative Example of Modeling Exelon Generation 2020 Total Gross Margin* South, Mid- Row Item Midwest ERCOT New York West, NE & Atlantic Canada (A) Start with fleet-wide open gross margin $4.05 billion (B) Capacity and ZEC $1.9 billion (C) Expected Generation (TWh) 96.4 48.5 24.5 15.7 (D) Hedge % (assuming mid-point of range) 52.5% 69.5% 45.5% 67.5% (E=C*D) Hedged Volume (TWh) 50.6 33.7 11.1 10.6 (F) Effective Realized Energy Price ($/MWh) $28.00 $37.00 $1.00 $34.00 (G) Reference Price ($/MWh) $25.12 $32.45 $9.71 $30.69 (H=F-G) Difference ($/MWh) $2.88 $4.55 ($8.71) $3.31 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $145 $155 ($95) $35 (J=A+B+I) Hedged Gross Margin ($ million) $6,200 (K) Power New Business / To Go ($ million) $700 (L) Non-Power Margins Executed ($ million) $150 (M) Non-Power New Business / To Go ($ million) $350 (N=J+K+L+M) Total Gross Margin* $7,400 million (1) Mark-to-market rounded to the nearest $5M 55 Q4 2018 Earnings Release Slides

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2019 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,075 $7,825 $7,550 Other Revenues(4) $(175) $(175) $(150) Direct cost of sales incurred to generate revenues for certain $(250) $(250) $(250) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,650 $7,400 $7,150 Key ExGen Modeling Inputs (in $M)(1,5) 2019 Other(6) $125 Adjusted O&M*(7) $(4,325) Taxes Other Than Income (TOTI)(8) $(400) Depreciation & Amortization*(9) $(1,125) Interest Expense $(400) Effective Tax Rate 21.0% (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates, gross receipts tax revenues and JExel Nuclear JV (5) ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture (6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in ExGen Renewables JV and Bloom (7) Adjusted O&M* includes $200M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) TOTI excludes gross receipts tax of $150M (9) 2020 Depreciation & Amortization is favorable to 2019 by $50M, while 2021 Depreciation & Amortization is favorable to 2019 by $25M 56 Q4 2018 Earnings Release Slides

2018A Earnings Waterfalls 57 Q4 2018 Earnings Release Slides

QTD Adjusted Operating Earnings* Waterfall $0.01 Distribution Investment $0.01 Other $0.58 $0.56 $0.00 ($0.01) $0.02 ($0.04) $0.03 $0.02 (4) $0.01 Favorable Load $0.03 Income Taxes $0.01 Tax Repairs Deduction $0.02 Rate Increases (5) $0.01 Other ($0.03) Other ($0.01) Other ($0.18) Market and Portfolio Conditions(1) ($0.01) Nuclear Outages(2) $0.04 Capacity Pricing $0.04 Illinois Zero Emission Credit Revenue $0.03 Tax Cuts and Jobs Act Savings $0.04 Other(3) 2017 (6) ExGen(7) ComEd PECO BGE PHI Corp 2018 Note: Amounts may not sum due to rounding (1) Primarily 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) Reflects lower operating and maintenance expense primarily due to lower labor, contracting and materials expense and the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017 (4) Reflects the absence of the 2017 impairment of certain transmission-related income tax regulatory assets (5) Reflects increased depreciation and amortization, uncollectible accounts expense and interest expense (6) 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 (7) Drivers reflect CENG ownership at 100% 58 Q4 2018 Earnings Release Slides

YTD Adjusted Operating Earnings* Waterfall $0.05 Distribution/Transmission Investment $0.01 Energy Efficiency Investment $0.01 Other $3.12 $0.07 $0.00 $0.07 $0.03 $0.00 $0.35 $2.62 $0.09 Rate Increases $0.02 Favorable Weather $0.07 Favorable Weather and Load ($0.04) Other (5) $0.02 Tax Repairs Deduction ($0.04) Increased Storm Costs ($0.02) Other ($0.02) Increased Storm Costs $0.02 Increased Transmission Rates $0.35 Zero Emission Credit Revenue(1) $0.19 Capacity Pricing $0.18 Tax Cuts and Jobs Act Savings $0.05 Nuclear Outages(2) ($0.46) Market and Portfolio Conditions(3) $0.04 Other(4) 2017 (6) ExGen(7) 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) Reflects lower operating and maintenance expense primarily due to the absence of EGTP costs resulting from its deconsolidation in the fourth quarter of 2017 (5) Reflects increased depreciation and amortization, uncollectible accounts expense and interest expense, partially offset by the absence of the 2017 impairment of certain transmission-related income tax regulatory assets (6) 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 (7) Drivers reflect CENG ownership at 100% 59 Q4 2018 Earnings Release Slides

2019E Earnings Waterfalls 60 Q4 2018 Earnings Release Slides

ComEd Adjusted Operating EPS* Bridge 2018 to 2019 $0.06 ($0.12) $0.70 - $0.80 $0.12 $0.04 Mutual Assistance $0.69 $0.02 Other ($0.07) D&A $0.10 Distribution & Transmission ($0.02) Energy Efficiency Amortization $0.04 Energy Efficiency ($0.01) Interest ($0.04) Mutual Assistance ($0.02) Other $0.02 Other RNF 2018A(3) RNF(1) O&M(2) Taxes/Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 20.2% 61 Q4 2018 Earnings Release Slides

PECO Adjusted Operating EPS* Bridge 2018 to 2019 $0.02 $(0.03) $0.45 - $0.55 $0.04 $0.48 $0.02 Storm ($0.02) D&A ($0.01) Interest Expense $0.06 Higher Transmission and Distribution Revenues/Other ($0.02) Weather RNF 2018A(3) RNF(1) O&M(2) Taxes/Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 13.2% 62 Q4 2018 Earnings Release Slides

BGE Adjusted Operating EPS* Bridge 2018 to 2019 $0.05 ($0.04) $0.33 $0.30 - $0.40 $0.03 Distribution ($0.02) D&A $0.02 Transmission ($0.02) Taxes/Interest Expense 2018A(3) RNF(1) Taxes/Other(2) 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 27.5% 63 Q4 2018 Earnings Release Slides

PHI Adjusted Operating EPS* Bridge 2018 to 2019 $0.02 ($0.06) $0.45 - $0.55 $0.11 $0.43 ($0.04) D&A $0.01 Cost Mgmt Initiatives ($0.02) Other $0.01 Reduction in one-time items in 2018 $0.07 Distribution $0.04 Transmission 2018A(3) RNF(1) O&M(2) Other 2019E(3,4) Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (2) O&M excludes regulatory items that are P&L neutral (3) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (4) Guidance assumes an effective tax rate for 2019 of 4.9% 64 Q4 2018 Earnings Release Slides

ExGen Adjusted Operating EPS* Bridge 2018 to 2019 $0.09 Cost Optimization $0.09 Nuclear Retirements $0.07 Outages ($0.02) Everett Marine Terminal ($0.08) NDTF Realized Gains ($0.01) Other ($0.01) Share Dilution ($0.03) Other $1.39 $0.00 ($0.12) $1.20 - $1.30 ($0.24) $0.22 $0.05 Nuclear Retirements ($0.03) Base Capex Depreciation ($0.13) Nuclear Retirements ($0.02) Other ($0.12) Capacity ($0.02) ZECs $0.03 Market Conditions 2018A(1) Gross Margin O&M Depreciation Other 2019E(1,2) & Amortization Note: Drivers add up to mid-point of 2019 adjusted operating EPS range (1) Shares Outstanding (diluted) are 969M in 2018 and 973M in 2019 (2) Guidance assumes a marginal tax rate of 25.5% for 2019 65 Q4 2018 Earnings Release Slides

Appendix Reconciliation of Non-GAAP Measures 66 Q4 2018 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation Three Months Ended December 31, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share ($0.18) $0.15 $0.13 $0.07 $0.06 ($0.07) $0.16 Mark-to-market impact of economic hedging activities 0.18 - - - - - 0.19 Unrealized losses related to NDT funds 0.25 - - - - - 0.25 Plant retirements and divestitures 0.10 - - - - - 0.10 Cost management program 0.01 - - - - - 0.02 Gain on contract settlement (0.06) - - - - - (0.06) Noncontrolling interests (0.08) - - - - - (0.08) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.23 $0.15 $0.13 $0.07 $0.07 ($0.07) $0.58 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 67 Q4 2018 Earnings Release Slides

Q4 QTD GAAP EPS Reconciliation (continued) Three Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share(1) $2.30 $0.12 $0.11 $0.08 $0.00 ($0.66) $1.94 Mark-to-market impact of economic hedging activities 0.01 - - - - - 0.01 Unrealized gains related to NDT funds (0.11) - - - - - (0.11) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-lived asset impairments 0.01 - - - 0.02 - 0.03 Plant retirements and divestitures 0.07 - - - - - 0.07 Cost management program 0.01 - - - - - 0.01 Vacation policy change (0.03) - - - (0.01) - (0.03) Change in environmental liabilities 0.03 - - - - - 0.03 Gain on deconsolidation of businesses (0.14) - - - - - (0.14) Reassessment of deferred income taxes (1.94) - (0.01) 0.01 0.03 0.61 (1.30) Noncontrolling interests 0.04 - - - - - 0.04 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.27 $0.13 $0.10 $0.08 $0.05 ($0.07) $0.56 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 recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 68 Q4 2018 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation Twelve Months Ended December 31, 2018 ExGen ComEd PECO BGE PHI Other Exelon 2018 GAAP Earnings (Loss) Per Share $0.38 $0.69 $0.47 $0.32 $0.41 ($0.20) $2.07 Mark-to-market impact of economic hedging activities 0.25 - - - - 0.01 0.26 Unrealized losses related to NDT funds 0.35 - - - - - 0.35 Long-lived asset impairments 0.04 - - - - - 0.04 Plant retirements and divestitures 0.53 - - - - - 0.53 Cost management program 0.04 - - - - - 0.05 Asset retirement obligation - - - - 0.02 - 0.02 Gain on contract settlement (0.06) - - - - - (0.06) Reassessment of deferred income taxes (0.03) - - - (0.01) 0.01 (0.02) Noncontrolling interests (0.12) - - - - - (0.12) 2018 Adjusted (non-GAAP) Operating Earnings (Loss) Per $1.39 $0.69 $0.48 $0.33 $0.43 ($0.18) $3.12 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. 69 Q4 2018 Earnings Release Slides

Q4 YTD GAAP EPS Reconciliation (continued) Twelve Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share(1) $2.86 $0.60 $0.46 $0.32 $0.38 ($0.63) $3.99 Mark-to-market impact of economic hedging activities 0.11 - - - - - 0.11 Unrealized gains related to NDT funds (0.34) - - - - - (0.34) Amortization of commodity contract intangibles 0.04 - - - - - 0.04 Merger and integration costs 0.05 - - - (0.01) - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.14) Long-lived asset impairments 0.32 - - - 0.02 - 0.34 Plant retirements and divestitures 0.22 - - - - - 0.22 Cost management program 0.03 - - 0.01 - - 0.04 Vacation policy change (0.03) - - - (0.01) - (0.03) Change in environmental liabilities 0.03 - - - - - 0.03 Bargain purchase gain (0.25) - - - - - (0.25) Gain on deconsolidation of businesses (0.14) - - - - - (0.14) Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) Reassessment of deferred income taxes (1.96) - (0.01) 0.01 0.04 0.56 (1.37) Tax settlements (0.01) - - - - - (0.01) Noncontrolling interests 0.12 - - - - - 0.12 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.04 $0.62 $0.45 $0.33 $0.36 ($0.19) $2.62 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 recast to reflect new accounting standards issued by the FASB and adopted as of January 1, 2018 70 Q4 2018 Earnings Release Slides

Projected GAAP to Operating Adjustments • Exelon’s projected 2019 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities; − Unrealized gains and losses from NDT funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Certain costs incurred related to plant retirements; − Certain costs incurred to achieve cost management program savings; − Other unusual items; and − Generation's noncontrolling interest related to CENG exclusion items. 71 Q4 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 72 Q4 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 73 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations Legacy Consolidated Q4 2018 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $75 $120 $210 $1,437 $1,842 Operating Exclusions $1 $5 $19 $7 $32 Adjusted Operating Earnings $76 $125 $229 $1,444 $1,874 Average Equity $1,084 $1,422 $2,636 $14,245 $19,387 Operating ROE (Adjusted Operating Earnings/Average Equity) 7.0% 8.8% 8.7% 10.1% 9.7% Legacy Consolidated Q4 2017 Operating ROE Reconciliation ($M) ACE Delmarva Pepco EXC EU Net Income (GAAP) $77 $121 $205 $1,308 $1,711 Operating Exclusions ($20) ($13) ($20) $28 ($24) Adjusted Operating Earnings $58 $108 $185 $1,336 $1,687 Average Equity $1,038 $1,330 $2,417 $13,003 $17,787 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.6% 8.1% 7.7% 10.3% 9.5% Note: Items may not sum due to rounding 74 Q4 2018 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) $700 $1,425 $850 $1,125 $4,200 ($225) $8,050 Other cash from investing activities - - - - ($275) - ($275) Counterparty collateral activity - - - - $100 - $100 Adjusted Cash Flow from Operations $700 $1,425 $850 $1,125 $4,025 ($225) $7,875 2019 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $450 $350 $125 $125 ($1,775) $150 ($575) Dividends paid on common stock $225 $500 $350 $350 $900 ($925) $1,400 Financing Cash Flow $675 $850 $475 $475 ($875) ($775) $825 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) ($50) Adjusted Ending Cash Balance(3) $1,775 Adjustment for Cash Collateral Posted ($550) GAAP Ending Cash Balance $1,225 (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 75 Q4 2018 Earnings Release Slides

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2018 2019 2020 2021 2022 GAAP O&M $5,475 $5,025 $4,925 $4,825 $4,850 Decommissioning(2) 50 50 50 50 50 Oyster Creek Retirement(4) (100) - - - - Direct cost of sales incurred to generate revenues for certain Constellation and (250) (250) (250) (250) (275) Power businesses(3) O&M for managed plants that are partially owned (400) (400) (425) (425) (425) Other (175) (100) (50) - - Adjusted O&M (Non-GAAP) $4,600 $4,325 $4,250 $4,200 $4,200 2019-2022 ExGen Available Cash Flow* and Uses of Cash Calculation ($M)(1) Cash from Operations (GAAP) $15,425 Other Cash from Investing and Financing Activities ($1,550) (5) Baseline Capital Expenditures ($3,350) Nuclear Fuel Capital Expenditures ($3,175) Change in Cash $400 Free Cash Flow before Growth CapEx and Dividend $7,750 (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) Oyster Creek includes $75M of decommissioning asset retirement obligations for retirement acceleration (5) Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments 76 Q4 2018 Earnings Release Slides