Delmarva Power & Light 8-K Exelon Reports Fourth Quarter and Full Year 2017 Results

Earnings Conference Call 4th Quarter 2017 February 7, 2018

2 Q4 2017 Earnings Release Slides 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 2016 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 24, Commitments and Contingencies; (2) Exelon’s Third Quarter 2017 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 18; 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.

3 Q4 2017 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, Exelon Nuclear Partners, 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

4 Q4 2017 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 54 of this presentation.

5 Q4 2017 Earnings Release Slides Milestones and Accomplishments Financial • Delivered FY 2017 GAAP earnings per share of $3.97 and adjusted operating earnings per share* of $2.60, within our guidance range • Updated dividend policy to 5% growth annually through 2020 • Tax reform legislation will benefit our utility customers through lower bills after committed rate adjustments while our shareholders benefit from additional utility rate base growth and lower tax rates at ExGen • Expanded cost management program from 3rd quarter 2017 will save an incremental $250M annually by 2020 • Effective capital deployment at ExGen: • Creation of Renewables JV with Hancock • ExGen Renewables IV project financing • Exit of EGTP portfolio Operational • Utilities performed largely at first quartile levels with especially strong results across key metrics: • BGE, ComEd and PECO achieved 1st decile performance in the System Average Interruption Frequency Index (SAIFI) • BGE and ComEd achieved 1st decile performance in the Customer Average Interruption Duration Index (CAIDI) • PHI achieved best ever performance on SAIFI and CAIDI • Invested $5.3B of capital into our utilities to improve reliability, replace aging infrastructure, and enhance customer experience • Total Exelon utilities collectively earned 9.5% ROE in 2017, the mid-point of our long-term range • Achieved 94.1%(1) nuclear capacity factor, producing a record 157 TWhs of nuclear generation Regulatory & Policy • Successful dismissal of legal challenges of NY and IL ZEC programs in federal district court; appeals process is ongoing • FERC recognized need to better understand the status of resilience of system. Created “Grid Resilience in Regional Transmission Organizations and Independent System Operators” order to seek input from RTOs on how market rules may need to be changed • Completed distribution rate cases providing $283M in revenue increases and another $114M of rate increases for FERC transmission assets Employees & Community • 2017 awards and recognitions include: Billion Dollar Roundtable, Civic 50, Top 50 Companies for Diversity, Best Places to Work in 2017, CEO Action for Diversity & Inclusion, and UN’s HeForShe • Exelon and our employees set a new record in corporate philanthropy and volunteerism, committing over $52M in giving and volunteering 210,000 hours • Recognized by Dow Jones Sustainability Index for 12th consecutive year and by NewsWeek Green rankings for 9th consecutive year • 2,200 employees, contractors and support personnel from Exelon’s six utilities mobilized to assist residents in the southeastern U.S. impacted by Hurricane Irma (1) Capacity factor excludes impacts of Salem

6 Q4 2017 Earnings Release Slides Proven Track Record of Improving Operational Performance Operations Metric At CEG Merger (2012) 2015 Q4 2017 BGE ComEd PECO PHI BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction N/A Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations No Gas Operations Overall Rank Electric Utility Panel of 24 Utilities(1) 23rd 2nd 2nd 18th Q1 Q2 Q3 Q4 Performance Quartiles • Best on record SAIFI and CAIDI performance for BGE, ComEd and PHI • Best on record Customer Satisfaction performance for BGE, ComEd and PECO • BGE, ComEd and PECO achieved 1st decile performance in SAIFI • BGE and ComEd achieved 1st decile performance in CAIDI • For the 5th consecutive year, BGE and PECO achieved top decile performance in Gas Odor Response. PHI improved by moving from 1st quartile in 2016 to top decile in 2017. (1) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer

7 Q4 2017 Earnings Release Slides Best in Class at ExGen and Constellation 74% retail power customer renewal rate 24% power new customer win rate 90% natural gas customer retention rate 25 month average power contract term Average customer duration of more than 5 years Stable Retail Margins Exelon Generation Operational Metrics • Continued best in class performance across our Nuclear fleet: − Capacity factor for Exelon owned and operated units was 94.1%(1) − This was the second consecutive year over 94% and the fourth out of the last five years topping 94% − Most nuclear power ever generated at 157 TWhs(2) − 2017 average refueling outage duration of 23 days, just over the Exelon record of 22 days set in 2016 • Strong performance across our Fossil and Renewable fleet: − Renewables energy capture: 95.8% − Power dispatch match: 98.8% Constellation Metrics Note: Statistics represent full year 2017 results (1) 2017 capacity factor includes FitzPatrick for the Exelon period of ownership and operation (March 31 to December 31, 2017) and excludes impacts of Salem (2) Reflects generation output at ownership

8 Q4 2017 Earnings Release Slides (1) Amounts may not add due to rounding 2017 Financial Results 2017 EPS Results(1) • Adjusted (non-GAAP) operating earnings* full year drivers versus $2.55 - $2.75 guidance: Utilities Reduced storm activity Lower O&M FAS 109 Reg. Asset Impairment Exelon Generation IL ZEC Timing $3.97 $0.38 $0.32 ($0.63) $0.60 $0.46 $2.84 $1.03 ($0.19) $0.62 $2.60 $0.33 $0.36 $0.45 $1.94 Q4 GAAP Earnings ($0.66) $0.12 $2.29 $0.11 $0.08 $0.00 $0.13 $0.05 $0.08 $0.55 $0.26 ($0.07) $0.10 FY Adjusted Operating Earnings* Q4 Adjusted Operating Earnings* ExGen BGE HoldCo PHI PECO ComEd FY GAAP Earnings

9 Q4 2017 Earnings Release Slides ($0.19) $0.62 $0.36 $0.45 $0.33 BGE ExGen HoldCo PHI ExGen $0.25 - $0.35 2017 Actual $1.03 $2.60(1) PECO BGE PHI ComEd PECO ComEd $2.90 - $3.20(2) 2018 Guidance ~($0.20) $1.35 - $1.45 $0.40 - $0.50 HoldCo $0.60 - $0.70 $0.40 - $0.50 2018 Adjusted Operating Earnings* Guidance Note: Amounts may not add due to rounding (1) 2017 results based on 2017 average outstanding shares of 949M (2) 2018 earnings guidance based on expected average outstanding shares of 969M Expect Q1 2018 Adjusted Operating Earnings* of $0.90 - $1.00 per share Key Year-Over-Year Drivers • BGE: Return to normal storm (historical average) and inflation impacts • PECO: Higher transmission revenue, offset by inflation and higher depreciation • PHI: Higher distribution and transmission revenue and absence of 2017 FAS 109 impact, partially offset by higher depreciation • ComEd: Increased capital investments to improve reliability in distribution and transmission • ExGen: Capacity and ZEC revenues (including recognition of 2017 IL ZEC), and tax reform, partially offset by market conditions

10 Q4 2017 Earnings Release Slides Our Capital Plan Drives Leading Rate Base Growth Capital Expenditures ($M) $21B of capital will be invested at Exelon utilities from 2018-2021 for grid modernization and customer satisfaction 2,125 1,725 1,850 1,850 1,000 1,100 1,050 1,000 800 850 825 825 1,500 1,400 1,500 1,500 2021E 5,150 5,100 5,225 2019E 2020E 5,400 2018E Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding (1) Rate base reflects year-end estimates Rate Base ($B)(1) 13.1 14.5 15.6 16.6 17.4 5.7 6.4 6.9 7.6 8.06.6 7.1 7.6 8.0 8.69.2 9.9 10.6 11.3 12.0 +7.4% 2021E 46.0 2020E 2017E 2019E 43.5 37.8 2018E 34.6 40.7 ComEd BGE PECO PHI

11 Q4 2017 Earnings Release Slides Mechanisms Cover Bulk of Rate Base Growth 3.0 1.8 1.8 1.5 11.51.1 1.0 1.1 2018E 0.2 3.2 Total 2021E 11.5 2.5 2.8 2019E 2020E 2.9 Of the approximately $11.5 billion of rate base growth Exelon Utilities forecasts over the next 4 years, ~70% will be recovered through existing formula and tracker mechanisms Rate Base Growth Breakout 2018-2021 ($B) 8.0 3.4 Base Rate Case Tracker/Formula Rate Note: Numbers may not add due to rounding

12 Q4 2017 Earnings Release Slides Q4 2017 Trailing 12 Month ROEs* vs Allowed ROE Twelve Month Trailing Earned ROEs* 9.7%9.9%9.9% Delmarva Consolidated Exelon Utilities Legacy Exelon Utilities Pepco ACE Allowed ROE* Note: Represents the 12-month periods ending 12/31/2016 and 12/31/2017, respectively. ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Transmission). 5.6% 5.6% 8.1% 6.3% 7.7% 7.5% 10.3% 10.5% 9.5% 9.5% Q4 2016

13 Q4 2017 Earnings Release Slides Exelon Utilities’ Distribution Rate Case Updates Pepco MD Order Authorized Revenue Requirement Increase(1) $32.4M Authorized ROE 9.50% Common Equity Ratio 50.15% Order Received 10/20/17 ACE NJ Order Authorized Revenue Requirement Increase(1) $43.0M Authorized ROE 9.60% Common Equity Ratio 50.47% Order Received 9/22/17 Delmarva MD Filing Per Settlement Revenue Requirement Increase(1) $13.4M Per Settlement ROE 9.50%(3) Per Settlement Common Equity Ratio N/A Order Expected 2/9/18 ComEd Filing (1) Revenue requirement includes changes in depreciation and amortization expense 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 in Q3 2017 and will implement full allowable rates on March 17, 2018, subject to refund (3) Solely for purposes of calculating the Allowance for Funds Used During Construction and regulatory asset carrying costs (4) On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $30.7 million in annual tax savings resulting from the enactment of the TCJA Delmarva DE Gas Filing Requested Revenue Requirement Increase(1,2) $11.0M Requested ROE 10.10% Requested Common Equity Ratio 50.52% Order Expected Q4 2018 Delmarva DE Electric Filing Requested Revenue Requirement Increase(1,2) $31.2M Requested ROE 10.10% Requested Common Equity Ratio 50.52% Order Expected Q3 2018 Pepco DC Electric Filing Requested Revenue Requirement Increase(1) $66.2M Requested ROE 10.10% Requested Common Equity Ratio 50.28% Order Expected 12/2018 Pepco MD Electric Filing Requested Revenue Requirement Increase(1,4) $10.7M Requested ROE 10.10% Requested Common Equity Ratio 50.28% Order Expected 7/31/18 Authorized Revenue Requirement Increase(1) $95.6M Authorized ROE 8.40% Common Equity Ratio 45.89% Order Received 12/6/17

14 Q4 2017 Earnings Release Slides Exelon Utilities EPS* Growth of 6-8% to 2021 $1.80 $2.00 $1.60 $2.10 $0.00 $1.70 $2.20 $1.50 $1.90 $2.00 2021E $2.20 2020E $2.10 2019E 2018E $1.80 $1.80 $1.70 U ti lit y A dju st ed O p erat in g E a rnin g s* Rate base growth combined with PHI ROE improvement drives EPS growth $1.50 $1.90 Exelon Utilities Operating Earnings* 2018-2021 Note: Includes after-tax interest expense held at Corporate for debt associated with existing utility investment

15 Q4 2017 Earnings Release Slides Gross Margin Category ($M) (1) 2018 2019 2020 2018 2019 Open Gross Margin (2,5) (including South, West, Canada hedged gross margin) $4,350 $3,900 $3,750 $450 $200 Capacity and ZEC Revenues (2,5,6) $2,300 $2,000 $1,850 - - Mark-to-Market of Hedges (2,3) $350 $400 $250 $(300) $(50) Power New Business / To Go $550 $750 $900 $(150) $(100) Non-Power Margins Executed $200 $100 $100 - - Non-Power New Business / To Go $300 $400 $400 - - Total Gross Margin* (4,5) $8,050 $7,550 $7,250 - $50 December 31, 2017 Change from September 30, 2017 Exelon Generation: Gross Margin Update • In 2018, Total Gross Margin is flat compared to September 30, 2017, with the retention of Handley Generating Station adding $50M, offset by the early retirement of Oyster Creek which lowers Gross Margin by $50M • In 2019, Total Gross Margin is up $150M on a combination of higher power prices, strengthening ERCOT spark spreads, and additional generation from Handley, partly offset by early retirement of Oyster Creek which lowers Gross Margin by $100M • Relative to 2019, 2020 Total Gross Margin is lower by $300M: − $150M lower driven by reduction in Open Gross Margin primarily related to TMI retirement − $150M lower Capacity revenues from lower PJM and NE capacity prices • Behind ratable hedging position reflects the upside we see in power prices − ~13-16% behind ratable in 2018 when considering cross commodity hedges Recent Developments (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, 2017, market conditions (5) Reflects Oyster Creek and TMI retirements in October 2018 and September 2019, respectively. EGTP removal impacts full year 2018, 2019, and 2020 and is adjusted for retaining Handley Generating Station. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production

16 Q4 2017 Earnings Release Slides Adjusted O&M* ($M)(1,2) 4,3004,2754,300 4,550 2018E 2020E 2019E 2021E -1.9% Cost optimization programs and planned nuclear plant closures drive lower total O&M (1) All amounts rounded to the nearest $25M (2) O&M and Capital Expenditures reflect removal of Oyster Creek and TMI in 2018 and 2019, respectively, and removal of EGTP in 2018 forward, adjusted for retaining Handley Generating Station (3) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (4) 2018E growth capital expenditures reflects a ~$175M shift of cash outlay from 2017A to 2018E related to timing of payments for the CCGT projects in Texas Driving Costs and Capital Out of the Generation Business 950 875 875 850 950 900 825 800 375 125 175 2018E 1,850 2019E 2,275 75 2021E 1,825 2020E 1,825 Capital Expenditures ($M)(1,3,4) Base Committed Growth Nuclear Fuel

17 Q4 2017 Earnings Release Slides ExGen’s Strong Available Cash Flow* Supports Utility Growth and Debt Reduction (~$0.4-$0.6) Utility Investment ($3.3-$3.7) Committed ExGen Growth CapEx (~$0.7) ExGen/HoldCo Debt Reduction External Dividend ExGen Cumulative Available Cash Flow 2018-2021(1) ~$7.6 ($2.7-$3.3) 2018-2021 Exelon Generation Available Cash Flow and Uses of Cash* ($B) Redeploying Exelon Generation’s available cash flow* to maximize shareholder value (1) Cumulative Available Cash Flow* is a midpoint of a range based on December 31, 2017, market prices. Sources include change in margin, tax sharing agreement, equity investments, equity distributions for renewables JV and Bluestem tax equity, and acquisitions and divestitures.

18 Q4 2017 Earnings Release Slides Impacts from Tax Reform (1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment (2) 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 of BBB at Exelon Corp 41%40% ExGen Post-Tax Reform ExGen Pre-Tax Reform Tax Impacts Key Takeaways 2018 2019 2020 2021 Cumulative Incremental Rate Base from Tax Policy Changes $0.9 $1.4 $1.7 $2.0 ExGen Effective Tax Rate 22% 22% 22% 21% Consolidated Effective Tax Rate 18% 19% 20% 20% Consolidated Cash Tax Rate 1% 4% 3% 3% 21%22% Corp Pre- Tax Reform Corp Target 18 - 20% Corp Post Tax Reform 2018 Exelon S&P FFO/Debt %*(1,2) • Changes in federal tax policy are expected to increase run- rate EPS by $0.10 per share in 2019 • Utility rate base is expected to be $1.7B higher in 2020 than prior disclosures • Generation cash flows will benefit from a lower tax rate and full expensing of capital with an effective tax rate of 22% in 2018-2020, and 21% in 2021 • Projected Exelon FFO/Debt is largely unchanged with ExGen metrics stronger and modest deterioration at the six regulated utilities, which remain at or above rating agency thresholds 2018 ExGen S&P FFO/Debt %* S&P Threshold Impact of tax reform on Exelon’s metrics is largely neutral given offsetting impacts between ExGen and utilities Reflects the increased free cash flow as a result of tax rates decreasing to 22% from an expected 33% in 2018

19 Q4 2017 Earnings Release Slides Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Current Ratings (2,3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A3 A2 A2 S&P BBB- BBB A- A- A- A A A Fitch BBB BBB A A A- A- A A- (1) Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment (2) Current senior unsecured ratings as of February 7, 2018, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco (3) All 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 of BBB at Exelon Corp (5) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* ExGen Debt/EBITDA Ratio*(5) Exelon S&P FFO/Debt %*(1,4) Credit Ratings by Operating Company 0% 5% 10% 15% 20% 25% 18%-20% 2018 Target 21% 0.0 1.0 2.0 3.0 4.0 2.0x 2.5x 2018 Target 3.0x Excluding Non-Recourse Book S&P Threshold

20 Q4 2017 Earnings Release Slides Raising Dividend Growth Rate to 5% Annually through 2020 2018E $1.38 $1.53 2019E 2020E 5% $1.31 2017A $1.45 Implied ExGen(2) Dividend Implied Exelon Utilities less HoldCo(2) Dividend Assuming a steady 70% payout ratio on Utility less HoldCo earnings, ExGen’s contribution to the Exelon dividend represents a modest payout on earnings and free cash flow Dividends per Share(1) (1) Quarterly dividends are subject to declaration by the board of directors (2) Total projected Dividend per Share (DPS) figures are illustrative of a 5% growth annually applied to the 2017 dividend. Implied Exelon Utilities contribution is based on a 70% payout on the midpoint of the EPS guidance band for Exelon Utilities less HoldCo. Implied ExGen contribution is based on the remaining balance between the illustrative total annual DPS and the Implied Exelon Utilities contribution.

21 Q4 2017 Earnings Release Slides Resiliency and Energy Market Reform Price Formation Resiliency • PJM has stated that it is committed to advancing its proposal to allow all resources to set LMP and to improving scarcity pricing • PJM issued “Proposed Enhancements to Energy Price Formation” whitepaper in November 2017 • January 8, 2018, FERC order on resilience invited RTOs to submit filings discussing potential paths forward for addressing any identified gaps or exposure on the resilience of the bulk power system • “One of the most important things that we have been focused on is how does our market . . . actually compensate for resources that are providing reliability services? We've proposed key reforms and have engaged in discussion about key reforms on what we call price formation…we're looking for FERC and certainly we'll work with FERC to put time discipline on these discussions to address these in a timely manner.” - PJM CEO and President Andrew Ott at Senate ENR Committee hearing on January 23, 2018 • FERC issued “Grid Reliability and Resilience Pricing” order on January 8, 2018, to open new docket on resilience • “The Commission recognizes that we must remain vigilant with respect to resilience challenges, because affordable and reliable electricity is vital to the country’s economic and national security.” – January 8 order at 1 • “[W]e are not ending our work on the issue of resilience. To the contrary, we are initiating a new proceeding to address resilience in a broader context” - January 8 order at 7 • “As we stated in our order, we appreciate the secretary reinforcing the importance of the resilience of our bulk power system as an issue that warrants further attention and, as we said in our order, prompt attention…. it's something where I have declared it, and our order declares it to be a matter of priority for this commission…Those are not words we utter very often -- it is a declared priority of the Commission ” - FERC Chairman Kevin McIntyre at Senate ENR Committee hearing on January 23, 2018 In 2018, FERC and PJM are considering action on price formation and valuing the attribute of resilience, both of which should directly benefit our 24x7 nuclear fleet

22 Q4 2017 Earnings Release Slides ZEC Updates New York ZEC Legal Challenges Illinois ZEC Legal Challenges Federal Case: • Case dismissed on July 25 and judgment entered on July 27 • “The ZEC program does not thwart the goal of an efficient energy market; rather, it encourages through financial incentives the production of clean energy” • On August 24, the plaintiffs appealed to the US Court of Appeals for the 2nd Circuit • Briefing schedule: − Plaintiff-Appellant Opening Brief filed October 13 −Reply Briefs filed on December 1 − Oral arguments scheduled for March 12 State case: • On January 22, the court partially affirmed and partially denied motion to dismiss • The case will proceed in the trial court and will likely be decided on motions for summary judgment, which could take up to a year • Both cases dismissed and judgment entered July 14 • “The ZEC program does not conflict with the Federal Power Act” • On July 17, both sets of plaintiffs appealed to the US Court of Appeals for the 7th Circuit • On July 18, the 7th Circuit consolidated the appeals and set a briefing schedule: − Plaintiff-Appellant Opening Brief filed August 28 −Reply Briefs filed on December 12 − Oral arguments occurred on January 3, 2018 – Judge requested supplemental briefings within 14 days • Supplemental briefs were filed on January 26 • Parties are awaiting further action by the court New Jersey ZEC • In December, two legislative committees in the New Jersey senate and assembly unanimously passed the nuclear diversity credit bill • On January 8th, the lame duck session of the NJ Legislature came to a close without a vote on the floor • At the time, Governor-elect Murphy expressed a preference to include support for nuclear in a broader clean energy legislative package that will provide a number of benefits for customers in NJ • On January 25, an expanded clean energy bill was introduced in the Senate, incorporating the same nuclear support provisions but recharacterizing them as ZECs to reflect new priorities • Exelon looks forward to continuing to work with Governor Murphy and the legislature in the upcoming session

23 Q4 2017 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

24 Q4 2017 Earnings Release Slides 2018 Business Priorities and Commitments Maintain industry leading operational excellence Effectively deploy $5.4B of 2018 utility capex Advance PJM power price formation changes in 2018 Prevail on legal challenges to the NY and IL ZEC programs Seek fair compensation for at-risk plants in NJ and PA Grow dividend at 5% rate Continued commitment to corporate responsibility

25 Q4 2017 Earnings Release Slides Additional Disclosures

26 Q4 2017 Earnings Release Slides Exelon Utilities EPS Growth of 6-8% from 2018-2021 $0.00 $1.30 $0.10 $1.90 $1.80 $1.70 $2.20 $1.40 $2.10 $1.60 $1.50 $1.20 $1.10 $2.00 2019E $1.90 2018E 2020E $2.05 $1.80 2017E 2016A $1.70 $1.60 $1.50 Utility growth rate remains 6-8%, driven by rate base growth and improving PHI ROEs Note: Includes after-tax interest expense held at Corporate for debt costs associated with utility investment. $1.75 Q4 2017 Operating Earnings* Q4 2016 Operating Earnings* $1.40 $1.30 $2.20 $1.60 $1.50 $1.10 $0.10 $1.70 $1.80 $0.00 $2.00 $1.90 $2.10 $1.20 2021E $2.20 2020E 2017A 2016A $2.00 $2.10 2018E $1.80 2019E $1.80 $1.70 $1.50 $1.90 $1.57 $1.41 $1.41 $1.40

27 Q4 2017 Earnings Release Slides Utility Capex and Rate Base vs. Previous Disclosure We will invest $21B of capital in utilities from 2018-2021, supporting rate base growth of 7.4% from 2017-2021 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. 3,575 3,550 3,275 1,175 1,025 925 975 525 600 575 575 3,275 2020E 4,825 4,775 2017E 5,275 2018E 2019E 5,175 Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 21.7 23.2 24.5 25.7 27.0 6.9 7.8 8.1 8.4 8.9 3.9 4.4 4.9 3.1 2019E 36.6 31.7 2016E 3.5 34.4 2018E 38.6 2017E +6.5% 40.8 2020E Electric Distribution Gas Delivery Electric Transmission 3,550 3,625 3,325 3,375 3,300 1,200 1,100 1,050 1,125 1,125 550 675 725 750 725 2019E 2020E 2018E 2021E 5,150 5,225 5,100 5,400 2017A 5,325 Q4 2017 Capital Expenditures ($M) Q4 2017 Rate Base ($B) 23.4 25.4 27.1 28.7 30.1 7.7 8.3 8.8 9.3 9.7 4.1 4.8 5.5 6.2 40.7 2018E +7.4% 2020E 2021E 43.5 2019E 46.0 34.6 2017E 37.8 3.4 Electric Transmission Electric Distribution Gas Delivery

28 Q4 2017 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. (1) Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program ComEd Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 1,800 1,750 1,400 1,500 1,475 400 375 325 350 375 2017A 2,200 2018E 2,125 1,725 1,850 2019E 2020E 2021E 1,850 ~$7.6B of Capital being invested from 2018-2021 9.5 10.5 11.3 11.9 12.4 4.03.93.73.6 3.4 15.6 2018E 17.4 14.5 1.0 2021E +7.5% 2020E 0.8 2019E 16.6 0.6 13.1 0.3 0.1 2017E Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 1,800 ,6 0 1,375 1,475 400 375 300 300 2,025 1,675 2018E 1,775 2019E 2020E 2,200 2017E 8.7 9.5 10.1 10.5 11.0 3.93.83.63.53.2 15.5 +6.8% 2020E 0.7 14.8 2019E 0.5 2018E 14.0 2016E 2017E 0.1 0.3 11.9 13.2 Electric Transmission Other(1) Electric Distribution

29 Q4 2017 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. PECO Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 450 450 475 450 475 100 125 100 200 225 275 275 250 825 2019E 850 2021E 825 2020E 75 75 2018E 775 800 2017A ~$3.3B of Capital being invested from 2018-2021 4.2 4.5 4.7 5.0 5.3 1.5 1.7 1.9 2.0 2.3 1.1 2021E +6.9% 2020E 1.1 7.6 2019E 8.6 8.0 6.6 0.9 1.0 0.9 2018E 7.1 2017E Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 475 500 500 475 125 100 175 200 200 200 775 750 75 2020E 2019E 800 2017E 75 775 2018E 4.0 4.2 4.4 4.6 4.9 1.0 1.1 1.11.4 .5 1.6 1.7 1.9 +5.8% 2020E 7.8 7.4 2019E 6.2 2017E 2018E 6.6 2016E 7.0 0.9 0.9 Gas Delivery Electric Distribution Electric Transmission

30 Q4 2017 Earnings Release Slides Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. BGE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 375 400 475 450 375 225 175 225 200 200 325 400 425 425 400 1,100 2018E 2017A 1,000 925 2021E 1,000 2019E 2020E 1,050 ~$4.2B of Capital being invested from 2018-2021 3.2 3.4 3.7 3.9 4.0 1.2 1.3 1.5 1.51.5 1.7 2.0 2.3 2.5 6.9 2018E 7.6 2019E 2017E 5.7 2021E 8.0 2020E +9.0% 6.4 1.0 Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 400 450 475 400 225 150 175 150 300 350 325 325 2017E 950 2020E 875 2019E 975 925 2018E 3.1 3.2 3.4 3.6 3.7 1 1 1.1 1.1 1.21.3 1.5 1.6 1.8 2.0 2016E 2017E 5.3 6.9 0.8 6.5 6.1 2018E 2019E 5.7 2020E +7.3% Electric Transmission Gas Delivery Electric Distribution

31 Q4 2017 Earnings Release Slides PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 925 1,025 975 975 950 475 425 375 475 475 2021E 1,500 50 2020E 1,500 50 2019E 1,400 50 1,425 1,500 50 50 2018E 2017A ~$5.9B of Capital being invested from 2018-2021 6.5 7.0 7.4 7.9 8.3 3.23.02.92.62.4 2017E 0.4 9.2 0.3 +6.8% 2021E 0.4 2019E 2020E 0.4 10.6 12.0 11.3 2018E 9.9 0.5 Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 900 950 925 925 425 400 375 450 50 50 1,425 1,400 50 2017E 1,375 2020E 50 2019E 1,350 2018E 6.0 6.3 6.6 7.0 7.4 2.7 2.42.32.0 2.5 0.4 0.4 2017E 10.5 9.4 9.9 2020E 0.3 8.9 2019E 2018E 0.3 2016E 8.3 +6.1% 0.3 Electric Distribution Gas Delivery Electric Transmission Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates.

32 Q4 2017 Earnings Release Slides ACE Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 175 200 200 200 150 125 175 125 125 75 300 2021E 2020E 225 2018E 375 2017A 2019E 325 300 ~$1.2B of Capital being invested from 2018-2021 1.3 1.5 1.6 1.7 1.8 0.8 0.8 0.9 1.0 1.1+8.0% 2018E 2.8 2.1 2019E 2.2 2.7 2.5 2021E 2020E 2017E Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 200 200 175 175 125 150 150 125 2019E 2020E 325 325 300 2018E 350 2017E 1.2 1.3 1.4 1.4 1.5 0.7 0 7 0.8 0.9 1.0+7.3% 2.5 2019E 2020E 2018E 2.1 2017E 2.3 2016E 2.0 1.9 Electric Distribution Electric Transmission Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates.

33 Q4 2017 Earnings Release Slides Delmarva Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 200 200 175 175 175 200 150 100 100 100 50 50 50 50 50 350 2019E 325 2020E 2021E 450 325 2018E 2017A 400 ~$1.4B of Capital being invested from 2018-2021 1.5 1.6 1.7 1.7 1.8 0.8 0.9 1.0 1.0 1.0 0.50.4 2019E 3.2 2021E +5.6% 3.3 2020E 2.9 2017E 2018E 0.4 3.1 0.3 2.7 0.4 Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 175 175 175 175 175 125 75 75 50 50 50 50 2019E 300 2020E 2018E 300 400 2017E 350 1.4 1.5 1.5 1.6 1.7 0.7 0 7 0.8 0.8 0.8 0.40.4 2.7 0.3 2017E 2.8 2019E 2020E +4.0% 2018E 2.7 2016E 0.3 2.4 0.3 2.5 Gas Delivery Electric Distribution Electric Transmission Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates.

34 Q4 2017 Earnings Release Slides Pepco Capital Expenditure and Rate Base Forecast Q4 2017 Capital Expenditures ($M) 550 600 575 600 625 125 125 150 250 300 2021E 950 2020E 850 2017A 2018E 675 750 725 2019E ~$3.3B of Capital being invested from 2018-2021 3.6 3.9 4.2 4.5 4.8 0.8 0.9 0.9 0.9 1.0 2021E +6.9% 5.8 2018E 4.7 2017E 4.4 2019E 5.1 2020E 5.4 Q4 2017 Rate Base ($B) Q4 2016 Capital Expenditures ($M) Q4 2016 Rate Base ($B) 525 575 575 575 125 125 150 250 2018E 2017E 650 700 2020E 725 825 2019E 3.3 3.5 3.7 4.0 4.3 0 9 0.9 0.8 0.9 4.8 2018E 5.2 +6.7% 2020E 2019E 4.6 2017E 4.4 4.0 2016E 0.7 Electric Transmission Electric Distribution Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates.

35 Q4 2017 Earnings Release Slides Adjusted O&M* – Q4 2017 ($M)(1) Adjusted O&M* - Q4 2016 ($M) 4,3004,2754,3004,550 -1.9% 2021E 2020E 2018E 2019E Capital and O&M now reflect removal of EGTP(4), Oyster Creek, and TMI (1) O&M and Capital Expenditures reflect removal of Oyster Creek and TMI in 2018 and 2019, respectively, and removal of EGTP in 2018 forward, adjusted for retaining Handley Generating Station (2) Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments (3) 2018E growth capital expenditures reflects a ~$175M shift of cash outlay from 2017A to 2018E related to the CCGT projects in Texas (4) Adjusted for retaining Handley Generating Station ExGen O&M and Capex vs. Previous Disclosure 950 875 875 850 950 900 825 8002,275 375 1,850 75 2018E 1,825 125 2019E 2021E 1,825 175 2020E Base Nuclear Fuel Committed Growth 1,050 1,000 925 875 950 900 925 850 850 125 2019E 1,975 1,850 125 2020E 2,850 2018E 2,075 175 2017E Capex – Q4 2017 ($M)(1,2,3) Capex - Q4 2016 ($M)(2) 4,7754,7254,7254,850 -0.5% 2020E 2017E 2019E 2018E

36 Q4 2017 Earnings Release Slides Adjusted O&M* Forecast • Expect Compound Annual Growth Rate of -1.1% for 2018-2021 (1) All amounts rounded to the nearest $25M and may not add due to rounding $4,550 $1,250 $775 $975 $750 $4,800 $1,300 $725 $1,000 $700 2018 Guidance(1) -$175 ComEd -$150 BGE $8,125 ComEd PHI ExGen PECO PECO BGE HoldCo ExGen 2017 Actual(1) $8,375 PHI HoldCo Key Year-over-Year Drivers • BGE: Return to normal storm (historical average) and inflation impacts • PHI: Merger related synergies and lower pension expense, partially offset by inflation • PECO: Return to normal storm (historical average) and inflation impacts • ComEd: O&M favorability primarily driven by completion of EIMA infrastructure programs • ExGen: Cost management initiative, impact of outages and absence of EGTP ($ in millions)

37 Q4 2017 Earnings Release Slides Comparing Winter 2017/2018 and the 2014 Polar Vortex 2014 Polar Vortex vs. 2017/2018 Winter Generation Forced Outages(1) +23,000MW Improvement Generation Fuel Mix (MW)(2) Key Takeaways • PJM power prices cleared at times over ~$200/MWh during the 2017/2018 winter, but were not as high as during the 2014 Polar Vortex • Gas prices, while strong, were also not as high as polar vortex • Unplanned outages during the 2017/2018 winter were much lower than experienced during the Polar Vortex, in part reflecting the benefits of improved reliability associated with the capacity performance improvements • On the days with the highest gas prices, oil units ran and replaced eastern gas units (1) Source: PJM Cold Weather Summary report, dated January 9, 2018 (2) Source: PJM M W s

38 Q4 2017 Earnings Release Slides ExGen Forward Total Gross Margin* Walk: Q4 2017 vs. Q3 2017 $50 $8,050 Oyster Creek Handley $8,050 Q3 Q4 ($50) $50 $7,500 $7,550 Q3 Handley Energy Prices Q4 ($100) Oyster Creek $100 $7,250 2020 Energy Prices Capacity Revenues(2) $7,550 ($50) TMI ($100) ($150) 2019 FY 2018 ($M)(1,3,4,5) FY 2019 ($M)(1,3,4) FY 2020 versus FY 2019 ($M)(1,3,4) Key Takeaways • In 2018, Total Gross Margin is flat compared to September 30, 2017, reflecting a $50M increase from retention of Handley Generating Station, and $50M decrease from the early retirement of Oyster Creek − Strong quarter executing on $150M of power new business • In 2019, total gross margin is up $50M, reflecting $100M increase on higher power prices and strengthening ERCOT spark spreads plus $50M from additional generation from Handley, partially offset by the early retirement of Oyster Creek • Relative to 2019, 2020 Total Gross Margin is lower by $300M: − $150M lower primarily driven by Open Gross Margin related to TMI retirement − $150M lower Capacity revenues from lower PJM and NE capacity prices (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Based on December 31, 2017, market conditions (4) Reflects Oyster Creek and TMI retirements in October 2018 and September 2019, respectively. EGTP removal impacts full year 2018, 2019, and 2020 and is adjusted for retaining Handley Generating Station. (5) 2018 includes $150M of IL ZEC revenues associated with 2017 production

39 Q4 2017 Earnings Release Slides 2018 Projected Sources and Uses of Cash Consistent and reliable free cash flows Enable growth & value creation Supported by a strong balance sheet Strong balance sheet enables flexibility to raise and deploy capital for growth  $1.4B of long-term debt at the utilities, net of refinancing, to support continued growth Operational excellence and financial discipline drives free cash flow reliability  Generating $6.1B of free cash flow, including $1.9B at ExGen and $4.0B at the Utilities Creating value for customers, communities and shareholders  Investing $5.8B of growth capex, with $5.4B at the Utilities and $0.4B at ExGen (1) All amounts rounded to the nearest $25M. Figures may not add due to rounding. (2) Gross of posted counterparty collateral (3) Figures reflect cash CapEx and CENG fleet at 100% (4) Other Financing primarily includes expected changes in money pool borrowings, tax sharing from the parent, debt issue costs, tax equity cash flows, capital leases, and renewable JV distributions (5) Financing cash flow excludes intercompany dividends and other intercompany financing activities (6) ExGen Growth CapEx primarily includes Texas CCGTs, W. Medway, and Retail Solar (7) Dividends are subject to declaration by the Board of Directors (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities ($M)(1) BGE ComEd PECO PHI Total Utilities ExGen Corp(8) Exelon 2018E Cash Balance Beginning Cash Balance*(2) 1,400 Adjusted Cash Flow from Operations* (2) 625 1,625 600 1,125 3,975 3,875 275 8,100 Base CapEx and Nuclear Fuel(3) 0 0 0 0 0 (2,000) (25) (2,025) Free Cash Flow* 625 1,625 600 1,125 3,975 1,875 225 6,075 Debt Issuances 300 1,300 700 750 3,050 0 0 3,050 Debt Retirements 0 (850) (500) (250) (1,600) 0 0 (1,600) Project Financing n/a n/a n/a n/a n/a (100) n/a (100) Equity Issuance/Share Buyback 0 0 0 0 0 0 0 0 Contribution from Parent 100 450 50 225 850 0 (850) 0 Other Financing(4) 175 300 25 (75) 425 (100) (50) 275 Financing*(5) 600 1,200 275 650 2,725 (200) (900) 1,625 Total Free Cash Flow and Financing 1,200 2,850 875 1,775 6,700 1,675 (675) 7,700 Utility Investment (1,000) (2,125) (800) (1,500) (5,400) 0 0 (5,400) ExGen Growth(3,6) 0 0 0 0 0 (375) 0 (375) Acquisitions and Divestitures 0 0 0 0 0 0 0 0 Equity Investment 0 0 0 0 0 (25) 0 (25) Dividend(7) 0 0 0 0 0 0 (1,325) (1,325) Other CapEx and ividend (1,000) (2,125) (800) (1,500) (5,400) (400) (1,325) (7,125) Total Cash Flow 225 700 75 275 1,300 1,275 (2,000) 575 Ending Cash Balance*(2) 1,975

40 Q4 2017 Earnings Release Slides Exelon Debt Maturity Profile(1) 1,594 312 500 910 800 833 500 850 360 763 295 175 1,430 675 700 600 650 1,200 185 788 350 900 258 1,023 2,512 623 750741 833 750 807 1,150 300 900 1,275 2047 1,225 2043 1,400 2042 2041 2040 2039 2044 2046 2045 2032 2031 78 2030 2029 53 2028 97 2027 2026 2038 2037 2036 2035 2034 2033 2025 2024 2023 2022 2021 1,189 2020 2019 2018 ExCorp PHI Holdco ExGen EXC Regulated 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 2017 10-K GAAP financials; ExGen debt includes legacy CEG debt As of 12/31/17 ($M) BGE 2.6B ComEd 7.8B PECO 3.1B PHI 5.9B ExGen recourse 6.8B ExGen non-recourse 2.2B HoldCo 6.3B Consolidated 34.7B LT Debt Balances (as of 12/31/17) (1,2)

41 Q4 2017 Earnings Release Slides • Discount rates changes of +/- 50 bps result in -/+ $65M - $85M change in pension and OPEB combined 2015 expense (EPS impact of ~$0.05) Pension and OPEB Contributions and Expense 2017 2018 (in $M) Pre-Tax Expense(1) Contributions Pre-Tax Expense (Benefit) (1) Contributions Qualified Pension (2) (3) (4) $445 $315 $420 $300 Non-Qualified Pe sion 20 25 25 30 OPEB(3)(4) - 65 (5) 45 Total $465 $405 $440 $375 (1) Pension and OPEB expenses assume a 30% and 25% capitalization rate in 2017 and 2018, respectively (2) The Balanced Funding Strategy for the Qualified Plans provides pension funding of the greater of $250M or minimum required contributions plus amounts required to avoid benefit restrictions and at-risk status for the legacy Exelon plans. PHI qualified plan contributions were $60M in 2017 and are expected to be $50M in 2018. (3) Expected return on pension and OPEB plan assets is 7.00% and 6.60%, respectively, for both 2017 and 2018 (4) The discount rates used to determine costs for the majority of Exelon’s pension and OPEB plans were 4.04% and 3.62% for 2017 and 2018, respectively

42 Q4 2017 Earnings Release Slides Pension – Funded Status and Performance (3.8) (1.2) (1.2) (4.3) 2.6 Interest, Service & Other Costs Asset Investment Returns 16.1% Discount Rate 3.62% from 4.05% Contribution 0.3 80% Funded 83% Funded Pension 2017 Funded Status (PBO) Comparison ($B) December 31, 2016 Funded Status December 31, 2017 Funded Status

43 Q4 2017 Earnings Release Slides 2018 2019 2020 Henry Hub Natural Gas + $1/MMBtu $0.15 $0.32 $0.50 - $1/MMBtu ($0.15) ($0.31) ($0.47) NiHub ATC Energy Price + $5/MWh $0.06 $0.16 $0.26 - $5/MWh ($0.05) ($0.16) ($0.26) PJM-W ATC Energy Price + $5/MWh $0.02 $0.08 $0.13 - $5/MWh ($0.01) ($0.07) ($0.12) ComEd ROE $0.03 $0.03 $0.04 Pension Expense - $0.03 $0.03 Cost of Debt ($0.00) ($0.00) ($0.01) Share count (millions) 969 972 975 Exelon Consolidated Effective Tax Rate 18% 19% 20% Ex G en E PS Im pa ct * (1 ) In te re st R at e Se nsi ti vi ty t o +5 0 B P EPS Sensitivities (1) Based on December 31, 2017, 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.

44 Q4 2017 Earnings Release Slides Historical Nuclear Capital Investment 625 625 650 575 575 600 550 700 650 600 600 575 250 325 250 175 175 150 175 100 -0.8% 2021E 575 2020E 600 2019E 600 2018E 650 2017A 775 50 25 2016A 650 75 25 2015A 925 2014A 850 2013A 825 50 25 2012A 975 25 50 2011A 1,000 50 2010A 900 25 Significant historical investments have mitigated asset management issues and prepared sites for license extensions already received, reducing future capital needs. In addition, internal cost initiatives have found more cost efficient solutions to large CapEx spend, such as leveraging reverse engineering replacements rather than large system wide modifications, resulting in baseline CAGR of -0.8%, even with net addition of 2 sites. (1) Reflects accrual capital expenditures with CENG at 50% ownership. Assumes Oyster Creek and TMI retirements in October 2018 and September 2019, respectively. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Includes CENG beginning in April 2014 and FitzPatrick beginning in April of 2017, excludes Salem and Fort Calhoun (6) 2017 industry average excluding Exelon was not available at time of publication Nuclear Baseline (excluding Fuel) (2,3) Fukushima Growth(4) Cancelled Growth Nuclear Baseline CAGR 94.1%94.6%93.7%94.3%94.1% 92.7%93.3% 93.9% 90.0%90.0%89.2%89.3% 84.6%85.3% 87.6% 2017(6) 2016 2015 2014 2013 2012 2011 2010 Exelon Industry Average Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Capacity Factor(5)

45 Q4 2017 Earnings Release Slides 2017 Exelon Recognition and Partnerships Sustainability Corporate & Foundation Giving Corporate Recognition Diversity & Inclusion Workforce Dow Jones Sustainability Index Exelon named to Dow Jones Sustainability Index for 12th consecutive year Newsweek Magazine’s Green Rankings Newsweek Magazine’s Green Rankings recognized our leadership in sustainability, where we ranked third among utilities, No. 12 in the U.S. 500 and 24th among the Global 500 Carbon Reduction A recent U.S. Environmental Protection Agency report noted Exelon’s generation fleet had the lowest rate of emissions among the 20 largest public or privately held energy producers. Fortune also recognized Exelon as the second-lowest carbon emitter of all Fortune 100 companies Land for People Award Received the Trust for Public Land’s national “Land for People Award” in recognition of Exelon’s deep support of environmental stewardship, creating new parks and promoting conservation $52.1 million Last year, Exelon and its employees set all-time records, committing more than $52.1 million to non-profit organizations and volunteering more than 210,000 hours Civic 50 Exelon was named for the first time to the Civic 50, recognizing the most community-minded companies by Points of Light, the world’s largest organization dedicated to volunteer service 2017 Laurie D. Zelon Pro Bono Award For exemplary pro bono service and leadership Kids in Need of Defense Innovation Award Exelon's legal department and the Baltimore chapter of Organization of Latinos at Exelon (OLE) for their work with unaccompanied minors from Central America HeforShe Exelon joined U.N. Women’s HeForShe campaign, which is focused on gender equality. Pledge includes a $3 million commitment to develop new STEM programs for girls and young women and improving the retention of women at Exelon by 2020 Billion Dollar Roundtable Exelon became the first energy company to join the Billion Dollar Roundtable, an organization that promotes supplier diversity for corporations achieving $1 billion or more in annual direct spending with minority and women-owned businesses CEO Action for Diversity & Inclusion Exelon joined 150 leading companies for the CEO Action for Diversity & Inclusion™ , the largest CEO-driven commitment aimed at taking action to cultivate a workplace where diverse perspectives and experiences are welcomed and respected DiversityInc Top 50 DiversityInc. named Exelon as one of the Top 50 companies for excellence in diversity. Indeed.com “50 Best Places to Work” Indeed.com ranked Exelon No. 18 on its “50 Best Places to Work.” Human Rights Campaign “Best Places to Work” For the third consecutive year, HRC's Corporate Equality Index gave Exelon a perfect rating on its best places to work for LGBTQ 2017 U.S. Veterans Magazine’s “Best of the Best” Most veteran-friendly companies Historically Black Engineering Schools Top Supporter recognition for five consecutive years

46 Q4 2017 Earnings Release Slides Exelon Generation Disclosures December 31, 2017

47 Q4 2017 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d ge d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over Time Align Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure

48 Q4 2017 Earnings Release Slides Components of Gross Margin Categories Open Gross Margin •Generation Gross Margin at current market prices, including ancillary revenues, nuclear fuel amortization and fossils fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin for South, West and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for five major regions. Provided indirectly for each of the five major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin linked to power production and sales Gross margin from other business activities (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

49 Q4 2017 Earnings Release Slides Gross Margin Category ($M) (1) 2018 2019 2020 Open Gross Margin (including South, West & Canada hedged GM) (2,5) $4,350 $3,900 $3,750 Capacity and ZEC Revenues (2,5,6) $2,300 $2,000 $1,850 Mark-to-Market of Hedges (2,3) $350 $400 $250 Power New Business / To Go $550 $750 $900 Non-Power Margins Executed $200 $100 $100 Non-Power New Business / To Go $300 $400 $400 Total Gross Margin* (4,5) $8,050 $7,550 $7,250 Reference Prices (4) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) $2.83 $2.81 $2.82 Midwest: NiHub ATC prices ($/MWh) $27.93 $26.94 $26.91 Mid-Atlantic: PJM-W ATC prices ($/MWh) $33.51 $30.72 $30.12 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $6.21 $5.85 $5.30 New York: NY Zone A ($/MWh) $29.14 $26.15 $25.48 New England: Mass Hub ATC Spark Spread ($/MWh) ALQN Gas, 7.5HR, $0.50 VOM $5.84 $5.10 $5.63 ExGen Disclosures (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, 2017, market conditions (5) Reflects Oyster Creek and TMI retirements in October 2018 and September 2019, respectively. EGTP removal impacts full year 2018, 2019, and 2020 and is adjusted for removal of Handley Generating Station. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production

50 Q4 2017 Earnings Release Slides Generation and Hedges 2018 2019 2020 Exp. Gen (GWh) (1) 201,500 201,200 191,400 Midwest 95,900 97,200 96,700 Mid-Atlantic (2,6) 59,600 54,200 48,600 ERCOT 24,200 24,500 22,000 New York (2,6) 15,400 16,600 15,500 New England 6,400 8,700 8,600 % of Expected Generation Hedged (3) 85%-88% 55%-58% 26%-29% Midwest 82%-85% 51%-54% 22%-25% Mid-Atlantic (2,6) 88%-91% 65%-68% 33%-36% ERCOT 81%-84% 54%-57% 26%-29% New York (2,6) 94%-97% 57%-60% 26%-29% New England 92%-95% 35%-38% 38%-41% Effective Realized Energy Price ($/MWh) (4) Midwest $29.50 $29.50 $31.00 Mid-Atlantic (2,6) $36.00 $37.50 $38.50 ERCOT (5) $4.50 $3.50 $2.00 New York (2,6) $36.00 $32.00 $30.00 New England (5) $1.00 $5.00 $9.00 ExGen Disclosures (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 93.4%, 94.9% 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 and TMI retirements in October 2018 and September 2019, respectively. EGTP removal impacts full year 2018, 2019, and 2020 and is adjusted for retaining Handley Generating Station.

51 Q4 2017 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on December 31, 2017, 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 Gross Margin* Sensitivities (with existing hedges) (1) 2018 2019 2020 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $190 $410 $645 - $1/MMBtu $(190) $(400) $(615) NiHub ATC Energy Price + $5/MWh $75 $210 $345 - $5/MWh $(70) $(210) $(340) PJM-W ATC Energy Price + $5/MWh $30 $100 $165 - $5/MWh $(15) $(90) $(160) NYPP Zone A ATC Energy Price + $5/MWh - $30 $55 - $5/MWh - $(35) $(55) Nuclear Capacity Factor +/- 1% +/- $40 +/- $35 +/- $35

52 Q4 2017 Earnings Release Slides ExGen Hedged Gross Margin* Upside/Risk 6,000 6,500 7,000 7,500 8,000 8,500 9,000 2018 2019 2020 A p p ro xima te G ro ss Margin* ( $ m illion )( 1 ,2 ,3 ) $8,250 $7,800 $8,150 $7,150 (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 December 31, 2017 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions (3) Reflects Oyster Creek and TMI retirements in October 2018 and September 2019, respectively. EGTP removal impacts full year 2018, 2019, and 2020 and is adjusted for retaining Handley Generating Station. $6,650 $8,450

53 Q4 2017 Earnings Release Slides Row Item Midwest Mid-Atlantic ERCOT New York New England South, West & Canada (A) Start with fleet-wide open gross margin (B) Capacity and ZEC (C) Expected Generation (TWh) 97.2 54.2 24.5 16.6 8.7 (D) Hedge % (assuming mid-point of range) 52.5% 66.5% 55.5% 58.5% 36.5% (E=C*D) Hedged Volume (TWh) 51.0 36.0 13.6 9.7 3.2 (F) Effective Realized Energy Price ($/MWh) $29.50 $37.50 $3.50 $32.00 $5.00 (G) Reference Price ($/MWh) $26.94 $30.72 $5.85 $26.15 $5.10 (H=F-G) Difference ($/MWh) $2.56 $6.78 ($2.35) $5.85 ($0.10) (I=E*H) Mark-to-Market value of hedges ($ million)(1) $130 $245 ($30) $55 $0 (J=A+B+I) Hedged Gross Margin ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin* $100 $400 $7,550 million $3.9 billion $6,300 $750 $2 billion Illustrative Example of Modeling Exelon Generation 2019 Gross Margin* (1) Mark-to-market rounded to the nearest $5 million

54 Q4 2017 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) $8,500 $8,025 $7,700 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date - - - Other Revenues(4) $(200) $(175) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(250) $(300) $(250) Total Gross Margin* (Non-GAAP) $8,050 $7,550 $7,250 (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 Exelon Nuclear Partners, 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, and includes nuclear decommissioning trust fund earnings from unregulated sites, and the minority interest in ExGen Renewables JV and Bloom (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 Key ExGen Modeling Inputs (in $M)(1,5) 2018 Other(6) $150 Adjusted O&M* $(4,550) Taxes Other Than Income (TOTI)(7) $(375) Depreciation & Amortization(8) $(1,125) Interest Expense $(400) Effective Tax Rate 22.0%

55 Q4 2017 Earnings Release Slides 2017A Earnings Waterfalls

56 Q4 2017 Earnings Release Slides QTD Adjusted Operating Earnings* Waterfall $0.04 $0.08 $0.00 Corp $0.02 $0.00 BGE PHI ExGen(3) ($0.03) Q4 2017 $0.55 Q4 2016 PECO $0.44 ComEd $0.08 Zero Emission Credit Revenue(1) $0.05 Capacity Pricing $0.02 NEIL Insurance Refund ($0.07) Market and Portfolio Conditions(2) ($0.02) Favorable 2016 Baltimore City Conduit Fee Settlement ($0.01) Income Taxes(4) $0.03 Increased Distribution and Transmission Rates ($0.03) Income Taxes(4) Note: Amounts may not sum due to rounding (1) Reflects the impact of the New York ZECs (2) Includes the unfavorable impact of lower realized energy prices and the conclusion of the Ginna Reliability Support Services Agreement (3) Reflects CENG ownership at 100% (4) Reflects a 2017 impairment of certain transmission-related income tax regulatory assets $0.03 Distribution and Transmission Rate Base $0.01 Other

57 Q4 2017 Earnings Release Slides FY Adjusted Operating Earnings* Waterfall $0.11 $0.05 ComEd $2.60 ($0.24) 2017 Corp PHI $0.02 BGE PECO ($0.03) ExGen(4) $0.01 $2.68 2016 ($0.42) Market and Portfolio Conditions(1) ($0.07) O&M Impact of Outages(2) ($0.03) Interest Expense $0.20 Zero Emission Credit Revenue(3) $0.07 Capacity Pricing $0.01 Other $0.04 Increased Distribution and Transmission Rates $0.03 2016 Rate Case Disallowances $0.01 Decreased Storm Costs ($0.02) Favorable 2016 Baltimore City Conduit Fee Settlement ($0.02) Depreciation & Amortization ($0.01) Income Taxes(6) ($0.01) Other $0.12 Increased Distribution and Transmission Rates ($0.03) Income Taxes(6) $0.02 Other(7) Note: Amounts may not sum due to rounding (1) Includes the unfavorable impact of lower realized energy prices, the impacts of lower load volumes delivered due to mild weather in the third quarter 2017, the conclusion of the Ginna Reliability Support Services Agreement and the impact of declining natural gas prices on Generation’s natural gas portfolio (2) Driven by higher planned nuclear outage days in 2017; excludes Salem (3) Reflects the impact of the New York ZECs (4) Reflects CENG ownership at 100% (5) Beginning in 2017 for ComEd, customer rates are adjusted to eliminate the impacts of weather and customer usage on distribution volumes. (6) Reflects a 2016 favorable adjustment at BGE, and 2017 impairments at BGE and PHI, of certain transmission-related income tax regulatory assets (7) PHI reflects full year of earnings in 2017 versus earnings from March 24, 2016, through December 31, 2016 $0.07 Distribution and Transmission Rate Base $0.01 U.S. Treasuries (Distribution ROE) ($0.02) 2016 Weather(5) ($0.01) Other ($0.02) Weather Revenue Net Fuel ($0.01) Depreciation & Amortization

58 Q4 2017 Earnings Release Slides 2018E Earnings Waterfalls

59 Q4 2017 Earnings Release Slides ComEd Adjusted Operating EPS* Bridge 2017 to 2018 $0.04 Distribution & Transmission $0.03 Energy Efficiency ($0.01) ROE (US Treasury yields) ($0.03) Depreciation & Amortization ($0.02) Energy Efficiency Amortization Note: Drivers add up to mid-point of 2018 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 949M in 2017 and 969M in 2018 (4) Guidance assumes an effective tax rate for 2018 of 20.7% (5) Excludes the reductions to revenue related to tax reform that are directly offset by lower income tax expense $0.02 EIMA projects completion $0.01 Other $0.03 $0.06 Other(3,4,5) 2017A Interest Depreciation & Amortization ($0.05) O&M(2) RNF(1,5) $0.00 ($0.01) 2018E $0.60 - $0.70 $0.62

60 Q4 2017 Earnings Release Slides $0.05 $0.40 - $0.50 2018E(3,4) $0.45 Taxes/Other(5) RNF(1,5) ($0.02) 2017A O&M(2) ($0.03) PECO Adjusted Operating EPS* Bridge 2017 to 2018 Note: Drivers add up to mid-point of 2018 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 949M in 2017 and 969M in 2018 (4) Guidance assumes an effective tax rate for 2018 of 3.6% (5) Excludes the reductions to revenue related to tax reform that are directly offset by lower income tax expense ($0.02) Storm ($0.01) Inflation $0.03 Transmission Revenue/Electric DSIC $0.02 Weather RNF ($0.02) Depreciation/Gross Receipt Tax

61 Q4 2017 Earnings Release Slides $0.25 - $0.35 $0.33 ($0.04) 2017A RNF(1,5) O&M(2,5) $0.01 2018E(3,4) BGE Adjusted Operating EPS* Bridge 2017 to 2018 Note: Drivers add up to mid-point of 2018 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 949M in 2017 and 969M in 2018 (4) Guidance assumes an effective tax rate for 2018 of 19.8% (5) Excludes the reductions to revenue related to tax reform that are directly offset by lower income tax expense $0.01 Other RNF ($0.02) Storm ($0.01) Inflation ($0.01) Other

62 Q4 2017 Earnings Release Slides $0.09 $0.40 - $0.50 2018E(3,4) Other(5) ($0.01) O&M(2) RNF(1,5) $0.01 2017A $0.36 PHI Adjusted Operating EPS* Bridge 2017 to 2018 $0.03 FAS 109 ($0.02) D&A ($0.02) Other Note: Drivers add up to mid-point of 2018 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 949M in 2017 and 969M in 2018 (4) Guidance assumes an effective tax rate for 2018 of 13.2% (5) Excludes the reductions to revenue related to tax reform that are directly offset by lower income tax expense $0.08 Revenue $0.01 Weather

63 Q4 2017 Earnings Release Slides $0.10 Other $1.35 - $1.45 2018E(1,2) Gross Margin* 2017A O&M* Depreciation & Amortization $0.06 $0.24 $1.03 ($0.03) ExGen Adjusted Operating EPS* Bridge 2017 to 2018 Note: Drivers add up to mid-point of 2018 adjusted operating EPS range (1) Shares Outstanding (diluted) are 949M in 2017 and 969M in 2018 (2) Guidance assumes a marginal tax rate of 25.1% for 2018 $0.29 IL ZEC $0.18 Capacity $0.06 NY ZEC ($0.42) Market Conditions $(0.01) Other $0.14 Cost Optimization $0.04 Outages $0.03 EGTP $0.03 Other ($0.02) Baseline Capex Depreciation ($0.01) Other $0.20 Tax Reform ($0.06) NDTF Realized Gains ($0.02) Share Dilution ($0.06) Other

64 Q4 2017 Earnings Release Slides Exelon Utilities Rate Case Filing Summaries

65 Q4 2017 Earnings Release Slides 12/17 1/18 2/18 Delmarva – DE Electric Distribution Rates Delmarva – MD Electric Distribution Rates Exelon Utilities’ Distribution Rate Case Schedule 3/18 4/18 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, and Delaware Public Service Commission and are subject to change 5/18 Delmarva – DE Gas Distribution Rates ComEd Electric Distribution Formula Rate Commission Order Received Dec 6 Settlement Filed Dec 18 Commission Order Expected Feb 9 Intervenor Direct Testimony Feb 21 Intervenor Direct Testimony Mar 13 Pepco Electric Distribution Rates - MD 2018 Formula Rate Update Filing April Case Filed Jan 2 Pepco Electric Distribution Rates - DC Case Filed Dec 19 Rebuttal Testimony Apr 6 Evidentiary Hearings May 15-17 Rebuttal Testimony May 8 6/18 Intervenor Direct Testimony Apr 13 Rebuttal Testimony May 11 Evidentiary Hearings June 4-13 Initial Briefs June 20 Reply Briefs June 29

66 Q4 2017 Earnings Release Slides Pepco MD (Electric) Distribution Rate Case Filing Formal Case No. 9472 Test Year January 1, 2017 – December 31, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.28% Requested Rate of Return ROE: 10.10%; ROR: 7.74% Proposed Rate Base (Adjusted) $1.8B Requested Revenue Requirement Increase (Updated on February 5, 2018) $10.7M Residential Total Bill % Increase 1.81% Notes • January 2, 2018, Pepco MD filed application with Maryland Public Service Commission (MDPSC) seeking increase in electric distribution base rates • On February 5, 2018, Pepco filed with the MDPSC an update to its current distribution rate case to reflect approximately $30.7 million in annual tax savings resulting from the enactment of the TCJA • Forward looking reliability plant additions through June 2018 ($7.8M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request • Request for Rate Phase-In of $14.9M on $126M of plant (to cover reliability capital May 2018 to April 2019) and commitment to not file new case before January 1, 2020 Procedural Schedule: • Intervenor Direct Testimony Due: April 13, 2018 • Rebuttal Testimony Due: May 11, 2018 • Evidentiary Hearings: June 4-13, 2018 • Initial Briefs due: June 28, 2018 • Final Briefs due: July 13, 2018 • Commission Order Expected: July 31, 2018

67 Q4 2017 Earnings Release Slides Pepco DC (Electric) Distribution Rate Case Filing Formal Case No. 1150 Test Year January 1, 2017 – December 31, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.28% Requested Rate of Return ROE: 10.10%; ROR: 7.74% Proposed Rate Base (Adjusted) $1.9B Requested Revenue Requirement Increase $66.2M Residential Total Bill % Increase 9.24% Notes • December 19, 2017, Pepco DC filed application with Public Service Commission of the District of Columbia (PSCDC) seeking increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • Forward looking reliability plant additions through December 2018 ($7.9M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Procedural Schedule: • Commission Order Expected: December 2018

68 Q4 2017 Earnings Release Slides Delmarva DE (Gas) Distribution Rate Case Filing 68 Docket No. 17-0978 Test Year January 1, 2017– December 31, 2017 Test Period 6 months actual and 6 months estimated Requested Common Equity Ratio 50.52% Requested Rate of Return ROE: 10.10%; ROR: 6.98% Proposed Rate Base (Adjusted) $345M Requested Revenue Requirement Increase (Updated on November 7, 2017) $11.0M(1) Residential Total Bill % Increase 9.9% Notes • August 17, 2017, Delmarva DE filed application with Delaware Public Service Commission (DPSC) seeking increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase reliability and customer service • Forward looking reliability plant additions through August 2018 ($1.0M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Procedural Schedule • Intervenor Direct Testimony Due: March 13, 2018 • Rebuttal Testimony Due: May 8, 2018 • Evidentiary Hearings: July 17-19, 2018 • Initial Briefs Due: August 23, 2018 • Reply Briefs Due: September 6, 2018 • Commission Order Expected: Q4 2018 (1) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on November 1, 2017, and will implement full allowable rates on March 17, 2018, subject to refund

69 Q4 2017 Earnings Release Slides Delmarva DE (Electric) Distribution Rate Case Filing 69 Docket No. 17-0977 Test Year January 1, 2017– December 31, 2017 Test Period 6 months actual and 6 months estimated Requested Common Equity Ratio 50.52% Requested Rate of Return ROE: 10.10%; ROR: 6.98% Proposed Rate Base (Adjusted) $805M Requested Revenue Requirement Increase $31.2M(1) Residential Total Bill % Increase (Updated on October 18, 2017) 4.7% Notes • August 17, 2017, Delmarva DE filed application with DPSC seeking increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • Forward looking reliability plant additions through August 2018 ($3.1M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Procedural Schedule: • Intervenor Direct Testimony Due: February 21, 2018 • Rebuttal Testimony Due: April 6, 2018 • Evidentiary Hearings: May 15-17, 2018 • Initial Briefs Due: June 20, 2018 • Reply Briefs Due: June 29, 2018 • Commission Order Expected: Q3 2018 (1) As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on October 16, 2017, and will implement full allowable rates on March 17, 2018, subject to refund

70 Q4 2017 Earnings Release Slides Delmarva MD (Electric) Distribution Rate Case Filing Formal Case No. 9455 Per Filed Settlement Test Year October 1, 2016 – September 30, 2017 Test Period 7 months actual and 5 months estimated (Updated to 12+0 on November 16, 2017) Requested Common Equity Ratio 50.68% Requested Rate of Return ROE: 10.10%; ROR: 7.05% ROE: 9.50%(1) Proposed Rate Base (Adjusted) $741M Requested Revenue Requirement Increase (Updated on Nov. 16, 2017) $19.3M $13.4M Residential Total Bill % Increase 1.8% 1.9% Notes • July 14, 2017, Delmarva MD filed application with Maryland Public Service Commission (MDPSC) seeking increase in electric distribution base rates • Forward looking reliability and other plant additions through April 2018 ($3.1M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Intervenor Positions: • Office of People’s Council (OPC) revenue increase of $5.0M or $7.2M based on 8.65% or 9.0% ROE, respectively • Staff revenue increase of $11.1M based on 9.30% ROE Procedural Schedule: • Commission Order Expected: February 9, 2018 • Settlement filed December 18, 2017, and evidentiary hearings held on January 5, 2018 Key Settlement Provisions: • Regulatory asset/liability treatment related to costs/savings for Winter Storm Stella, AMI savings and Costs to Achieve • Staff will convene a work group with DPL & OPC reps to evaluate DPL’s MD reliability spend and projected reliability performance from 2017 through 2020 • Prior to next filing, DPL will provide Staff and OPC education and training sessions addressing how Class Cost of Service Study (CCOSS) model functions (1) Settlement states cost of equity solely for purposes of calculating AFUDC (Allowance for Funds Used During Construction) and regulatory asset carrying costs shall be 9.50%

71 Q4 2017 Earnings Release Slides ComEd Distribution Rate Case Filing Docket # 17-0196 Filing Year • 2016 Calendar Year Actual Costs and 2017 Projected Net Plant Additions are used to set the rates for calendar year 2018. Rates currently in effect (docket 16-0259) for calendar year 2017 were based on 2015 actual costs and 2016 projected net plant additions. Reconciliation Year • Reconciles Revenue Requirement reflected in rates during 2016 to 2016 Actual Costs Incurred. Revenue requirement for 2016 is based on docket 15- 0287 (2014 actual costs and 2015 projected net plant additions) approved in December 2015. Requested Common Equity Ratio 45.89% Requested Rate of Return ~ROE: 8.40%; ROR: ~6.50% Proposed Rate Base (Adjusted) ~$9.7B Requested Revenue Requirement Increase $95.6M Residential Total Bill % Increase 0.8% Notes • April 13, 2017, ComEd filed application with Illinois Commerce Commission seeking increase in electric distribution base rates • Size of ask is driven by continued investments in electric distribution system to maintain and increase reliability and customer service • $9,662 million– Filing year (represents projected year-end rate base using 2016 actual plus 2017 projected capital additions). 2017 and 2018 earnings will reflect 2017 and 2018 year-end rate base respectively. • $8,807 million - Reconciliation year (represents year-end rate base for 2016) • $95.6M increase ($17.5M increase due to the 2016 reconciliation and collar adjustment in addition to a $78.1M increase related to the filing year). The 2016 reconciliation impact on net income was recorded in 2016 as a regulatory asset. Procedural Schedule: • Commission Order Received: December 06, 2017 • Rates are effective January 1, 2018

72 Q4 2017 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

73 Q4 2017 Earnings Release Slides Q4 QTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP (Loss) Earnings Per Share $(0.04) $0.09 $0.10 $0.11 $0.03 $(0.06) $0.22 Mark-to-market impact of economic hedging activities (0.05) - - - - - (0.05) Unrealized losses related to NDT fund investments 0.01 - - - - - 0.01 Amortization of commodity contract intangibles 0.03 - - - - - 0.03 Merger and integration costs 0.02 - - - - - 0.02 Reassessment of state deferred income taxes 0.02 - - - - - 0.01 Asset retirement obligation (0.08) - - - - - (0.08) Merger commitments 0.04 - - - 0.01 (0.01) 0.04 Plant retirements and divestitures 0.10 - - - - - 0.10 Cost management program 0.01 - - - - - 0.01 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 Noncontrolling interests 0.07 - - - - - 0.07 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.18 $0.09 $0.10 $0.11 $0.05 $(0.08) $0.44

74 Q4 2017 Earnings Release Slides Q4 QTD GAAP EPS Reconciliation (continued) NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP (Loss) Earnings Per Share $2.29 $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 fund investments (0.12) - - - - - (0.12) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs - - - - - - - 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 Reassessment of state deferred income taxes (1.94) - (0.01) 0.01 0.03 0.61 (1.30) Asset retirement obligation - - - - - - - Gain on deconsolidation of business (0.14) - - - - - (0.14) Vacation policy change (0.03) - - - (0.01) - (0.03) Change in environmental remediation liabilities 0.03 - - - - - 0.03 Noncontrolling interests 0.04 - - - - - 0.04 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.26 $0.13 $0.10 $0.08 $0.05 ($0.07) $0.55

75 Q4 2017 Earnings Release Slides Q4 YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Twelve Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.54 $0.41 $0.47 $0.31 ($0.07) ($0.44) $1.22 Mark-to-market impact of economic hedging activities 0.03 - - - - - 0.03 Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13) Amortization of commodity contract intangibles 0.04 - - - - - 0.04 Merger and integration costs 0.04 - - - 0.05 0.04 0.12 Long-lived asset impairments 0.11 - - - - - 0.11 Asset retirement obligation (0.08) - - - - - (0.08) Reassessment of state deferred income taxes 0.02 - - - - (0.01) 0.01 Merger commitments 0.05 - - - 0.27 0.16 0.47 Plant retirements and divestitures 0.47 - - - - - 0.47 Cost management program 0.03 - - - - - 0.04 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 Noncontrolling interests 0.11 - - - - - 0.11 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.27 $0.57 $0.48 $0.31 $0.25 ($0.20) $2.68

76 Q4 2017 Earnings Release Slides Q4 YTD GAAP EPS Reconciliation (continued) NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Twelve Months Ended December 31, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share $2.84 $0.60 $0.46 $0.32 $0.38 ($0.63) $3.97 Mark-to-market impact of economic hedging activities 0.11 - - - - - 0.11 Unrealized gains related to NDT fund investments (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 Reassessment of state deferred income taxes (1.96) - (0.01) 0.01 0.04 0.56 (1.37) Cost management program 0.03 - - 0.01 - - 0.04 Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) Tax settlements (0.01) - - - - - (0.01) Bargain purchase gain (0.25) - - - - - (0.25) Gain on deconsolidation of business (0.14) - - - - - (0.14) Vacation policy change (0.03) - - - (0.01) - (0.03) Change in Environmental Remediation Liabilities 0.03 - - - - - 0.03 Noncontrolling interests 0.12 - - - - - 0.12 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.03 $0.62 $0.45 $0.33 $0.36 ($0.19) $2.60

77 Q4 2017 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 to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements − Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the ConEdison Solutions and FitzPatrick acquisition dates − Certain merger and integration costs associated with the PHI and FitzPatrick acquisitions − Certain costs related to plant retirements − Costs incurred related to a cost management program − Generation’s noncontrolling interest, primarily related to CENG exclusion items − Other unusual items

78 Q4 2017 Earnings Release Slides (1) All amounts rounded to the nearest $25M and may not add due to rounding (2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. (3) Reflects impact of operating adjustments on GAAP EBITDA (4) Reflects other adjustments as prescribed by S&P (5) Reflects present value of net capacity purchases and present value of minimum future operating lease payments (6) Reflects after-tax underfunded pension/OPEB (7) Reflects non-recourse project debt (8) Reflects 75% of excess cash applied against balance of LTD YE 2018 Exelon FFO Calculation ($M) (1,2) GAAP Operating Income $3,450 Depreciation & Amortization $3,850 EBITDA $7,300 +/- Non-operating activities and nonrecurring items(3) $350 - Interest Expense ($1,400) + Current Income Tax (Expense)/Benefit $100 + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $275 = FFO (a) $7,700 YE 2018 Exelon Adjusted Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $33,075 Short-Term Debt $1,125 + PPA and Operating Lease Imputed Debt(5) $1,025 + Pension/OPEB Imputed Debt(6) $4,000 - Off-Credit Treatment of Debt(7) ($1,875) - Surplus Cash Adjustment(8) ($1,075) +/- Other S&P Adjustments(4) ($250) = Adjusted Debt (b) $36,025 YE 2018 Exelon FFO/Debt (1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

79 Q4 2017 Earnings Release Slides (1) All amounts rounded to the nearest $25M and may not add due to rounding (2) Calculated using S&P Methodology (3) Reflects impact of operating adjustments on GAAP EBITDA (4) Reflects other adjustments as prescribed by S&P (5) Reflects present value of net capacity purchases and present value of minimum future operating lease payments (6) Reflects after-tax underfunded pension/OPEB (7) Reflects non-recourse project debt (8) Reflects 75% of excess cash applied against balance of LTD YE 2018 ExGen FFO Calculation ($M) (1,2) GAAP Operating Income $1,025 Depreciation & Amortization $1,800 EBITDA $2,825 +/- Non-operating activities and nonrecurring items(3) $350 - Interest Expense ($400) + Current Income Tax (Expense)/Benefit ($225) + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $75 = FFO (a) $3,700 YE 2018 ExGen Adjusted Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $8,850 Short-Term Debt $0 + PPA and Operating Lease Imputed Debt(5) $700 + Pension/OPEB Imputed Debt(6) $1,700 - Off-Credit Treatment of Debt(7) ($1,875) - Surplus Cash Adjustment(8) ($700) +/- Other S&P Adjustments(4) $275 = Adjusted Debt (b) $8,950 YE 2018 ExGen FFO/Debt (1,2) FFO (a) = 41% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

80 Q4 2017 Earnings Release Slides YE 2018 ExGen Net Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $8,850 Short-Term Debt $0 - Surplus Cash Adjustment ($950) = Net Debt (a) $7,900 YE 2018 Book Debt / EBITDA Net Debt (a) = 2.5x Operating EBITDA (b) (1) All amounts rounded to the nearest $25M (2) Reflects impact of operating adjustments on GAAP EBITDA (3) Includes Exelon-operated nuclear plants, at ownership YE 2018 ExGen Operating EBITDA Calculation ($M) (1) GAAP Operating Income(3) $950 Depreciation & Amortization(3) $1,700 EBITDA(3) $2,650 +/- Non-operating activities and nonrecurring items(2) $525 = Operating EBITDA (b) $3,175 GAAP to Non-GAAP Reconciliations YE 2018 ExGen Net Debt Calculation ($M) (1,2) Long-Term Debt (including current maturities) $8,850 Short-Term Debt $0 - Surplus Cash Adjustment ($950) - Nonrecourse Debt ($2,075) = Net Debt (a) $5,825 YE 2018 Recourse Debt / EBITDA Net Debt (a) = 2.0x Operating EBITDA (b) YE 2018 ExGen Operating EBITDA Calculation ($M) (1) GAAP Operating Income(3) $950 Depreciation & Amortization(3) $1,700 EBITDA(3) $2,650 +/- Non-operating activities and nonrecurring items(2) $525 - EBITDA from projects financed by nonrecourse debt ($275) = Operating EBITDA (b) $2,900

81 Q4 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations Note: Amounts may not sum due to rounding (1) ACE, Delmarva, and Pepco represents full year of earnings Q4 2017 Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP) (1) $77 $121 $205 $1,308 $1,711 Operating Exclusions ($20) ($13) ($20) $28 ($24) Adjusted Operating Earnings (1) $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% Q4 2016 Operating ROE Reconciliation(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP) (1) ($42) ($9) $42 $1,102 $1,103 Operating exclusions $99 $89 $127 $146 $461 Adjusted Operating Earnings (1) $57 $80 $170 $1,258 $1,564 Average Equity $1,017 $1,282 $2,270 $11,951 $16,523 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.6% 6.3% 7.5% 10.5% 9.5%

82 Q4 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations 2018 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $1,625 $600 $625 $1,125 $4,125 $275 $8,375 Other cash from investing activities - - - - ($275) - ($275) Intercompany receivable adjustment - - - - - - - Counterparty collateral activity - - - - - - - Adjusted Cash Flow from Operations $1,625 $600 $625 $1,125 $3,875 $275 $8,100 2018 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $750 ($25) $400 $350 ($950) ($225) $300 Dividends paid on common stock $450 $300 $200 $300 $750 ($675) $1,325 Intercompany receivable adjustment - - - - - - - Financing Cash Flow $1,200 $275 $600 $650 ($200) ($900) $1,625 Exelon Total Cash Flow Reconciliation(1) 2018 GAAP Beginning Cash Balance $900 Adjustment for Cash Collateral Posted $500 Adjusted Beginning Cash Balance(3) $1,400 Net Change in Cash (GAAP)(2) $575 Adjusted Ending Cash Balance(3) $1,975 Adjustment for Cash Collateral Posted ($525) GAAP Ending Cash Balance $1,475 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Represents the GAAP measure of net change in cash, which is the sum of cash flow from operations, cash from investing activities, and cash from financing activities. Figures reflect cash capital expenditures and CENG fleet at 100%. (3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity

83 Q4 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations 2018-2021 ExGen Available Cash Flow and Uses of Cash Calculation ($M)(1) Cash from Operations (GAAP) $15,975 Other Cash from Investing and Financing Activities ($1,200) Baseline Capital Expenditures (4) ($3,675) Nuclear Fuel Capital Expenditures ($3,450) Free Cash Flow before Growth CapEx and Dividend $7,625 ExGen Adjusted O&M Reconciliation ($M)(1) 2018 2019 2020 2021 GAAP O&M $5,225 $5,000 $4,925 $4,950 Decommissioning(2) - - - - TMI Retirement - - - - Oyster Creek Retirement (25) - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (250) (300) (250) (250) O&M for managed plants that are partially owned (400) (400) (425) (425) Other - - 25 25 Adjusted O&M (Non-GAAP) $4,550 $4,300 $4,275 $4,300 (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