exc20171102992

Earnings Conference Call Third Quarter 2017 November 2, 2017

2 Q3 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 (to be filed on November 2, 2017) 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 Q3 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 Q3 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 34 of this presentation.

5 Q3 2017 Earnings Release Slides Note: Amounts may not sum due to rounding * Refer to pages 3 and 4 for information regarding non-GAAP financial measures Strong Third Quarter Results $0.85 $0.00 $0.20 $0.12 $0.16 $0.06 $0.32 Q3 2017 EPS Results • GAAP earnings were $0.85/share in Q3 2017 vs. $0.53/share in Q3 2016 • Adjusted operating earnings* were $0.85/share in Q3 2017 vs. $0.91/share in Q3 2016, at the mid-point of our guidance range of $0.80-$0.90/share HoldCo ComEd PECO PHI BGE ExGen Adjusted Operating Earnings* $0.85 ($0.04) $0.19 $0.12 $0.15 $0.07 $0.36 GAAP Earnings

6 Q3 2017 Earnings Release Slides Operating Highlights Q1 Q2 Q3 Q4 (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem Exelon Utilities Operational Metrics Exelon Generation Operational Metrics • Continued best in class performance across our Nuclear fleet: o Q3 Nuclear Capacity Factor: 96.1%(2) o Owned and operated Q3 production of 41 TWh was best on record • Strong performance across our Fossil and Renewable fleet: o Q3 Renewables energy capture: 95.9% o Q3 Power dispatch match: 98.4% • BGE and ComEd are meeting 1st decile performance in CAIDI • BGE, ComEd and PECO are on track for 1st decile performance in SAIFI • ComEd and PHI are meeting 1st decile performance in Service Level Operations Metric Q3 2017 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency)(1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations

7 Q3 2017 Earnings Release Slides Resiliency and Energy Market Reform Price Formation Resiliency • PJM has stated that it is prepared to implement its reforms allowing all resources to set LMP by mid-2018 • “FERC should expedite its efforts with states, RTO/ISOs, and other stakeholders to improve energy price formation in centrally-organized wholesale electricity markets.” – DOE Staff Report, August 2017 • The Commission should focus “first and foremost on the optimization of price formation in the energy and ancillary service markets.” Ill. Commerce Comm’n Comments at 7 • “PJM staff is proposing to reform the existing pricing model in order to ensure that the cost of serving load is reflected in LMP to the fullest extent possible… This follows the principles of sound market design.” - William W. Hogan, October 23, 2017 • “Accurately valuing resilience is not a zero-sum game. Compensating base-load generation does not equate to destruction of markets. On the contrary, I think it’s a step toward accurately pricing contributions of all market participants.” – FERC Chairman Neil Chatterjee, October 13, 2017 • “The unknowns are what we're going to have to deal with: if there was a physical attack, if you had [an explosion like the one on the Spectra pipeline that wasn’t] fixed in a timely manner heading into the winter heating season, central Pennsylvania would have had potential issues. . . So now the conversation's gotten broader around these cascading events, and then how do you price resiliency? That conversation needs to take place." FERC Commissioner Rob Powelson, October 27, 2017 • "We used to talk about equipment failure and outages caused by storms. Now, the threat profile has changed, the considerations are broader. There could be intentional attacks – cyber or physical. Those concerns lead us beyond reliability and into resilience." PJM CEO and President Andrew L. Ott, September 20, 2017 Exelon recommends that FERC: 1. Immediately require PJM to submit its energy price formation proposal 2. Require the affected RTOs to submit detailed information on the grid’s vulnerabilities to enable the development of a design basis threat analysis that can inform cost-effective market reforms, and 3. State that it will not interfere with state programs that value resilient resources like nuclear plants

8 Q3 2017 Earnings Release Slides HoldCo ComEd PECO PHI BGE ExGen Q3 2017 $0.85 $0.19 ($0.04) $0.15 $0.12 $0.07 $0.36 Q3 2017 Adjusted Operating EPS* Results Exelon Utilities – Reduced storm activity – Lower O&M Exelon Generation – Constellation Gross Margin – Timing of O&M Third Quarter Adjusted Operating Earnings* Drivers Q3 2017 vs. Guidance of $0.80 - $0.90 $0.49 Note: Amounts may not sum due to rounding

9 Q3 2017 Earnings Release Slides QTD Adjusted Operating Earnings* Waterfall Q3 2017 $0.85 Corp ($0.01) PHI $0.01 BGE $0.01 PECO ($0.01) ComEd ($0.01) ExGen ($0.05) Q3 2016 $0.91 ($0.19) Market and Portfolio Conditions(1) $0.08 Zero Emission Credit Revenue(2) $0.05 Capacity Pricing $0.01 Increased Transmission Rates $0.03 Increased Distribution Rates ($0.01) Weather ($0.01) Other Note: Amounts may not sum due to rounding (1) Includes the unfavorable impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon’s ratable hedging strategy (2) Reflects the impact of the New York Clean Energy Standard (3) Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes ($0.03) 2016 Weather(3) $0.01 Distribution and Transmission Rate Base $0.01 U.S. Treasuries (Distribution ROE) ($0.01) Income Taxes ($0.02) Weather $0.01 Tax Repair

10 Q3 2017 Earnings Release Slides ~($0.20) $0.40 - $0.50 $2.50 - $2.80(1) $0.60 - $0.70 $0.30 - $0.40 $1.05 - $1.15 $0.25 - $0.35 2017 Initial Guidance $1.00 - $1.10 $0.25 - $0.35 $0.30 - $0.40 $0.40 - $0.50 $0.60 - $0.70 $2.55 - $2.75(1) 2017 Revised Guidance ExGen BGE ExGen BGE PHI PECO ComEd HoldCo ~($0.15) HoldCo PECO ComEd PHI Narrowing 2017 Adjusted Operating Earnings* Guidance Range (1) 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not sum up to consolidated EPS guidance. (2) Revised guidance reflects delay in Illinois ZEC revenue recognition for 2017 until 2018, shifting $0.09 of EPS

11 Q3 2017 Earnings Release Slides Q3 2017 TTM Earned ROE Trailing 12 Month ROE vs Allowed ROE Twelve Month Trailing Earned ROEs* 9.7% 9.9%9.9% ACE Delmarva Consolidated EU Pepco(1) Legacy EU Allowed ROE Note: Represents the period from 10/1/2016 to 9/30/2017. ROEs represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Transmission). 5.9% 6.4% 7.8% 7.3% 7.7% 7.3% 10.3% 10.7% 9.5% 9.7% Q2 2017 TTM Earned ROE (1) Pepco MD Distribution allowed ROE is based on authorized ROE of 9.55% for the rates that were in effect during the trailing twelve month period. The order issued on 10/20/17 authorized an ROE of 9.50%.

12 Q3 2017 Earnings Release Slides Exelon Utilities‟ Distribution Rate Case Updates Pepco DC Order Authorized Revenue Requirement Increase(1) $36.9M Authorized ROE 9.50% Common Equity Ratio 49.14% Order Received 7/25/17 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 Requested Revenue Requirement Increase(1) $21.6M(4) Requested ROE 10.10% Requested Common Equity Ratio 50.68% Order Expected 2/14/18 ComEd Filing Requested Revenue Requirement Increase(1) $95.6M(2) Requested ROE 8.40% Requested Common Equity Ratio 45.89% Order Expected Q4 2017 (1) Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings (2) Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017 (3) As permitted by Delaware law, Delmarva Power will implement interim rate increases of $2.5M in Q3 2017 and will implement full allowable rates on March 17, 2018, subject to refund (4) Amount represents adjusted requested revenue requirement filed on September 28, 2017 Delmarva DE Gas Filing Requested Revenue Requirement Increase(1,3) $12.9M Requested ROE 10.10% Requested Common Equity Ratio 50.52% Order Expected Q3 2018 Delmarva DE Electric Filing Requested Revenue Requirement Increase(1,3) $31.2M Requested ROE 10.10% Requested Common Equity Ratio 50.52% Order Expected Q3 2018

13 Q3 2017 Earnings Release Slides Utility CapEx Update 2017 Exelon Utilities CapEx Spend ($M) Notable Projects • Pepco‟s Waterfront Substation − $182 million invested to date. Expected completion by end of 2017 − Part of “Capital Grid” project − Replaces aging infrastructure and improves substation performance − Will support existing customers and planned development in the Capitol Riverfront and Southwest Waterfront areas • ComEd‟s Grand Prairie Gateway transmission line − $203 million investment − 60-mile, 345kV line through four northern Illinois counties − Energized April 2017 − Estimated customer savings of $121 to $325 million, net of construct costs, within the first 15 years − Reduces carbon emissions by nearly 500,000 tons within the first 15 years FY Plan(1) $5,275 YTD Actual $3,805 Exelon Utilities on track to meet their 2017 capital investment commitments to the benefit of customers (1) FY Plan rounded to the nearest $25M

14 Q3 2017 Earnings Release Slides Exelon Generation: Gross Margin Update • Delay in recognition of Illinois ZEC revenues lowers the Capacity and ZEC Revenues line in 2017 by $150M and increases the 2018 line by $150M – see slide 21 for details • Excluding impact of Illinois ZEC timing: − In 2017, $50M reduction in Power New Business targets − In both 2018 and 2019, $100M reduction due to lower power and capacity prices and $100M reduction to Power New Business Targets • Behind ratable hedging position reflects the upside we see in power prices − ~11-14% behind ratable in 2018 when considering cross commodity hedges Recent Developments Gross Margin Category ($M) (1) 2017 2018 2019 2017 2018 2019 Open Gross Margin (2,5) (including South, West, Canada hedged gross margin) $3,600 $3,900 $3,700 $(150) $(100) $(100) Capacity and ZEC Revenues (2,5,6) $1,700 $2,300 $2,000 $(150) $100 $(50) Mark-to-Market of Hedges (2,3) $2,150 $650 $450 $250 $100 $50 Power N w Business / To Go $100 $700 $850 $(100) $(150) $(100) Non-Power Margins Executed $350 $200 $100 $50 $50 - Non-Power New Business / To Go $100 $300 $400 $(50) $(50) - Total Gross Margin* (4,5) $8,000 $8,050 $7,500 $(150) $(50) $(200) September 30, 2017 Change from June 30, 2017 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2017, market conditions (5) Reflects TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production

15 Q3 2017 Earnings Release Slides 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 Ann oun ced Cos t Re duct ions Cost Management is Integral to Our Business Strategy ExGen Forecast O&M* Q3 2017 ($M)(1) ExGen Forecast O&M*: Q3 2017 vs. Q4 2016(1) 125 225 150 25075 2018 4,300 2020 2019 4,450 4,600 50 2017 4,850 ExGen and BSC Cost Reductions Since Constellation Merger New Cost Reductions of $250M Run-Rate by 2020 (Q3 2017 Earnings Call) (1) Adjusted for TMI retirement and removal of EGTP, net of other expenses CEG Merger Synergies of $170M in 2012, $350M in 2013, and $500M Run-Rate beginning in 2014 CENG Service Agreement Run-Rate Synergies of $70M (2013 EEI) $350M Cost Management Program (2015 EEI) PHI Merger Run-Rate Synergies of $130M Cost Reductions of $100M in 2018 and $125M in 2019 (Q3 2016 Earnings Call) ExGen O&M ($M) 2017 2018 2019 2020 2017-2020 CAGR Q4 2016 O&M $4,850 $4,725 $4,725 $4,775 - 0.5% EGTP & TMI ($0) ($50) ($125) ($225) - Q4 „16 O&M, Net of EGTP & TMI $4,850 $4,675 $4,600 $4,550 -2.1% Cost Savings ($0) ($75) ($150) ($250) - Q3 2017 O&M $4,850 $4,600 $4,450 $4,300 -3.9% ExGen Total O&M Cost Reductions EGTP & TMI

16 Q3 2017 Earnings Release Slides ExGen‟s Strong Free Cash Flow Supports Utility Growth and Debt Reduction 2017-2020 Exelon Generation Free Cash Flow* and Uses of Cash ($B) (1) Sources include change in margin, tax parent benefit, equity investments, and acquisitions and divestitures Redeploying Exelon Generation‟s free cash flow to maximize shareholder value ($2.3 - $2.7) ($2.8 - $3.2) (~$1.3) Committed ExGen Growth CapEx ExGen/HoldCo Debt Reduction ~$6.8 Cumulative ExGen FCF 2017-2020(1) Utility Investment

17 Q3 2017 Earnings Release Slides Hurricane Support • More than 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 − Exelon teams shared our experience with severe weather restoration efforts and industry-leading best practices to lead one of the largest contingents of support nationally − Crews deployed for more than two weeks helping to restore power to nearly eight million customers in Florida and Georgia • Approximately 250 Exelon employee volunteers logged over 1,300 hours for disaster relief activities • Exelon and its employees contributed approximately $820,000 in disaster relief

18 Q3 2017 Earnings Release Slides The Exelon Value Proposition  Regulated Utility Growth with utility EPS rising 6-8% annually from 2017- 2020 and rate base growth of 6.5%, 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 2020 planning horizon  Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 2.5% annual dividend growth through 2018(1), • Debt reduction; and • Modest contracted generation investments (1) Quarterly dividends are subject to declaration by the board of directors

19 Q3 2017 Earnings Release Slides Additional Disclosures

20 Q3 2017 Earnings Release Slides 2017 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  $0.9B 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 $5.1B of free cash flow, including $1.4B at ExGen and $3.8B at the Utilities Creating value for customers, communities and shareholders  Investing $6.1B, with $5.3B at the Utilities and $0.8B at ExGen (1) All amounts rounded to the nearest $25M. Figures may not add due to rounding. (2) Gross of posted counterparty collateral (3) Figures reflect cash CapEx and CENG fleet at 100% (4) Other Financing includes primarily expected changes in short-term debt, money pool borrowings, tax sharing from the parent, debt issue costs, CENG borrowing from Sumitomo, tax equity cash flows, capital leases, and renewable JV proceeds (5) Financing cash flow excludes intercompany dividends and other intercompany financing activities (6) ExGen Growth CapEx primarily includes Texas CCGTs, AGE, W. Medway, and Retail Solar (7) Dividends are subject to declaration by the Board of Directors (8) Includes cash flow activity from Holding Company, eliminations, and other corporate entities Note: Numbers may not add due to rounding ($M)(1) BGE ComEd PECO PHI Total Utilities ExGen Corp(8) Exelon 2017E Cash Balance Beginning Cash Balance*(2) 1,050 Adjusted Cash Flow from Operations* (2) 775 1,025 750 1,175 3,750 3,350 75 7,150 Base CapEx and Nuclear Fuel(3) 0 0 0 0 0 (1,950) (50) (2,025) Free Cash Flow* 775 1,025 750 1,175 3,750 1,375 0 5,125 Debt Issuances 300 1,000 325 200 1,825 750 1,150 3,725 Debt Retirements (300) (425) 0 (150) (875) (700) (1,700) (3,275) Project Financing n/a n/a n/a n/a n/a 275 n/a 275 Equity Issuance/Share Buyback 0 0 0 0 0 0 1,150 1,150 Contribution from Parent 175 675 0 800 1,650 0 (1,625) 25 Other Financing(4) 150 350 150 (375) 275 50 425 725 Financing*(5) 350 1,600 475 450 2,875 350 (625) 2,625 Total Free Cash Flow and Financing 1,125 2,625 1,225 1,650 6,600 1,750 (600) 7,750 Utility Investment (925) (2,200) (775) (1,375) (5,250) 0 0 (5,250) ExGen Growth(3,6) 0 0 0 0 0 (800) 0 (800) Acquisitions and Divestitures 0 0 0 0 0 0 0 0 Equity Investment 0 0 0 0 0 (50) 0 (50) Dividend(7) 0 0 0 0 0 0 (1,225) (1,225) Other CapEx and Dividend (925) (2,200) (775) (1,375) (5,250) (875) (1,225) (7,350) Total Cash Flow 200 450 450 250 1,350 875 (1,850) 400 Ending Cash Balance*(2) 1,450

21 Q3 2017 Earnings Release Slides ExGen Forward Total Gross Margin* Walk: Q3 2017 vs. Q2 2017 Cumulative Rounding $50 Power New Business ($50) IL ZEC Timing ($150) Q2 $8,150 Q3 $8,000 $150 Q3 $8,050 IL ZEC Timing(5) Capacity Revenues(2,4) ($50) Energy Prices ($50) Power New Business ($100) Q2 $8,100 Energy Prices ($100) Q2 Capacity Revenues(2,4) ($50) $7,700 ($50) Power New Business $7,500 Q3 FY 2017 ($M)(1,3,4) FY 2018 ($M)(1,3,4) FY 2019 ($M)(1,3,4) Key Takeaways • Change in timing of Illinois ZEC contract finalization results in 2017 reduction of $150M on a rounded basis and 2018 increase of $150M • Aggressive bidding by market participants in a low volatility period is pressuring Wholesale margins and limiting C&I Retail growth; reduce Power New Business To Go by $100M in 2018 and 2019 to reflect continuation of current, low discipline market bidding behavior • Lower energy prices reduce Open Gross Margin by $50M in 2018 and 2019; October price recovery offsets 2019 declines • Lower observed capacity prices in NY and MISO reduce Capacity Revenues by $50M on a rounded basis in 2018 and 2019 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Based on September 30, 2017, market conditions (4) Reflects TMI and Oyster Creek retirements in September 2019 and December 2019, respectively (5) 2018 includes $150M of IL ZEC revenues associated with 2017 production

22 Q3 2017 Earnings Release Slides DRAFT Note: Amounts may not sum due to rounding * Refer to pages 3 and 4 for information regarding non-GAAP financial measures YTD Earnings Results $0.47 $0.50 $0.35 $0.35 $0.38 $0.31 $0.24 $0.25 $0.51 $0.76 ($0.12) Adjusted Operating Earnings* $2.05 GAAP Earnings $2.01 $0.06 YTD 2017 EPS Results • GAAP earnings were $2.01/share YTD 2017 vs. $1.00/share YTD 2016 • Adjusted operating earnings* were $2.05/share YTD 2017 vs. $2.24/share YTD 2016 ComEd PECO PHI BGE ExGen HoldCo

23 Q3 2017 Earnings Release Slides YTD Adjusted Operating Earnings* Waterfall $0.11 2017 $2.05 Corp ($0.01) PHI BGE $0.05 PECO ($0.02) ComEd $0.02 ExGen ($0.34) 2016 $2.24 ($0.37) Market and Portfolio Conditions(1) ($0.07) O&M Impact of Outages(2) ($0.03) Interest Expense $0.13 Zero Emission Credit Revenue(3) $0.04 Increased Distribution and Transmission Rates $0.03 2016 Rate Case Disallowances $0.01 Decreased Storm Costs ($0.03) Depreciation & Amortization $0.08 Increased Distribution Rates $0.03 Other(5) Note: Amounts may not sum due to rounding (1) Includes the unfavorable impact of the conclusion of the Ginna Reliability Support Services Agreement, the impacts of declining natural gas prices on Generation’s natural gas portfolio, the impacts of lower load volumes delivered due to mild weather and lower realized energy prices related to Exelon’s ratable hedging strategy (2) Driven by higher planned nuclear outages in 2017; excludes Salem (3) Reflects the impact of the New York Clean Energy Standard (4) Pursuant to the Illinois Future Energy Jobs Act, beginning in 2017, customer rates for ComEd are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution volumes (5) PHI reflects full nine months of earnings in 2017 versus earnings from March 24, 2016, through September 30, 2016 $0.02 Distribution and Transmission Rate Base $0.02 U.S. Treasuries (Distribution ROE) ($0.03) 2016 Weather & Load(4) ($0.03) Weather $0.01 Tax Repair ($0.02) Interest Expense

24 Q3 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 October 24, 2017, 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* (6) Reflects removal of EGTP (7) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018 ExGen Debt/EBITDA Ratio*(5,6,7) Exelon S&P FFO/Debt %*(1,4,6,7) Credit Ratings by Operating Company 0% 5% 10% 15% 20% 25% 18%-20% 2017 Target 21% 0.0 1.0 2.0 3.0 4.0 2.6x 3.1x 2017 Target 3.0x Excluding Non-Recourse Book S&P Threshold

25 Q3 2017 Earnings Release Slides Theoretical Dividend Affordability from Utility less HoldCo(1,2) Utility less HoldCo payout ratio falling consistently even as dividend grows (1) Chart is illustrative and shows theoretical payout ratio if utilities supported 100% of the external dividend and interest expense at HoldCo. Currently, the utilities have a payout ratio of 70% which covers the majority of the external dividend and interest expense at HoldCo with ExGen covering the remainder. (2) Board of directors has approved a policy of 2.5% per year dividend increase through 2018. For illustrative purposes only, the chart assumes the dividend continues to increase 2.5% per year through 2020, although the board has not yet established dividend policy for periods after 2018. Quarterly dividends are subject to declaration by the board of directors. 75% 79% 81% 84% 95% 90% 85% 80% 75% 70% 65% 60% 2020 2019 2018 2017 Utility Earnings Payout Ratio (less HoldCo) Midpoint of Payout Ratio Range

26 Q3 2017 Earnings Release Slides Exelon Generation Disclosures September 30, 2017

27 Q3 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

28 Q3 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

29 Q3 2017 Earnings Release Slides ExGen Disclosures Gross Margin Category ($M) (1) 2017 2018 2019 Open Gross Margin (including South, West & Canada hedged GM) (2,5) $3,600 $3,900 $3,700 Capacity and ZEC Revenues (2,5,6) $1,700 $2,300 $2,000 Mark-to-Market of Hedges (2,3) $2,150 $650 $450 Power New Business / To Go $100 $700 $850 Non-Power Margins Executed $350 $200 $100 Non-Power New Business / To Go $100 $300 $400 Total Gross Margin* (4,5) $8,000 $8,050 $7,500 Reference Prices (4) 2017 2018 2019 Henry Hub Natural Gas ($/MMBtu) $3.14 $3.05 $2.89 Midwest: NiHub ATC prices ($/MWh) $26.52 $27.45 $26.36 Mid-Atlantic: PJM-W ATC prices ($/MWh) $28.81 $30.77 $29.22 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM ($0.78) $1.22 $2.65 New York: NY Zone A ($/MWh) $24.38 $27.29 $26.67 New England: Mass Hub ATC Spark Spread ($/MWh) ALQN Gas, 7.5HR, $0.50 VOM $4.36 $3.99 $4.24 (1) Gross margin categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2017, market conditions (5) Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. (6) 2018 includes $150M of IL ZEC revenues associated with 2017 production

30 Q3 2017 Earnings Release Slides 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 15 refueling outages in 2017, 15 in 2018, and 11 in 2019 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 93.4%, 93.2% and 94.7% in 2017, 2018, and 2019, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2018 and 2019 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 ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. Generation and Hedges 2017 2018 2019 Exp. Gen (GWh) (1) 200,200 199,300 202,000 Midwest 95,900 95,800 97,000 Mid-Atlantic (2,6) 60,700 60,500 59,000 ERCOT 17,800 19,500 20,800 New York (2,6) 14,700 15,500 16,600 New England 11,100 8,000 8,600 % of Expected Generation Hedged (3) 98%-101% 79%-82% 45%-48% Midwest 97%-100% 74%-77% 41%-44% Mid-Atlantic (2,6) 98%-101% 90%-93% 51%-54% ERCOT 97%-100% 77%-80% 44%-47% New York (2,6) 99%-102% 71%-74% 43%-46% New England 103%-106% 86%-89% 52%-55% Effective Realized Energy Price ($/MWh) (4) Midwest $33.00 $29.50 $29.50 Mid-Atlantic (2,6) $44.00 $37.00 $39.00 ERCOT (5) $11.00 $3.50 $3.50 New York (2,6) $41.50 $37.50 $32.00 New England (5) $20.00 $2.50 $3.00

31 Q3 2017 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on September 30, 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) 2017 2018 2019 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $(20) $140 $515 - $1/MMBtu $(10) $(210) $(500) NiHub ATC Energy Price + $5/MWh - $120 $265 - $5/MWh - $(115) $(265) PJM-W ATC Energy Price + $5/MWh - $10 $150 - $5/MWh $5 $(40) $(145) NYPP Zone A ATC Energy Price + $5/MWh - $25 $40 - $5/MWh - $(20) $(45) Nuclear Capacity Factor +/- 1% +/- $10 +/- $35 +/- $35

32 Q3 2017 Earnings Release Slides ExGen Hedged Gross Margin* Upside/Risk 6,000 6,500 7,000 7,500 8,000 8,500 9,000 2017 2018 2019 A p p ro xima te G ro ss Margin* ( $ m illion )( 1 ,2 ,3 ) $8,050 $7,950 $8,250 $7,800 (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 2018 and 2019 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2017 (2) Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions (3) Reflects ownership of FitzPatrick as of April 1, 2017, and TMI and Oyster Creek retirements in September 2019 and December 2019, respectively. EGTP removal impacts partial year 2017 and full year 2018 and 2019. $7,050 $8,300

33 Q3 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) 95.8 60.5 19.5 15.5 8.0 (D) Hedge % (assuming mid-point of range) 75.5% 91.5% 78.5% 72.5% 87.5% (E=C*D) Hedged Volume (TWh) 72.3 55.4 15.3 11.2 7.0 (F) Effective Realized Energy Price ($/MWh) $29.50 $37.00 $3.50 $37.50 $2.50 (G) Reference Price ($/MWh) $27.45 $30.77 $1.22 $27.29 $3.99 (H=F-G) Difference ($/MWh) $2.05 $6.23 $2.28 $10.21 ($1.49) (I=E*H) Mark-to-Market value of hedges ($ million)(1) $150 $345 $35 $115 ($10) (J=A+B+I) Hedged Gross Margin ($ 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* $200 $300 $8,050 million $3.9 billion $6,850 $700 $2.3 billion Illustrative Example of Modeling Exelon Generation 2018 Gross Margin* (1) Mark-to-market rounded to the nearest $5 million

34 Q3 2017 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,575 $8,575 $8,025 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(150) $(200) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(475) $(325) $(325) Total Gross Margin* (Non-GAAP) $8,000 $8,050 $7,500 (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, 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 $125M (8) Excludes P&L neutral decommissioning depreciation (9) Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants in service as of May and June of 2017. Capitalized interest will be an additional ~$25M lower in 2018 as well due to this. Key ExGen Modeling Inputs (in $M)(1,5) 2017 Other(6) $175 Adjusted O&M* $(4,850) Taxes Other Than Income (TOTI)(7) $(400) Depreciation & Amortization(8) $(1,075) Interest Expense(9) $(400) Effective Tax Rate 32.0%

35 Q3 2017 Earnings Release Slides Exelon Utilities‟ Rate Case Filing Summaries

36 Q3 2017 Earnings Release Slides 9/17 10/17 11/17 12/17 Delmarva – DE Electric Distribution Rates Delmarva – MD Electric Distribution Rates ACE Electric Distribution Rates - NJ Exelon Utilities‟ Distribution Rate Case Schedule 1/18 2/18 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, and Delaware Public Service Commission and are subject to change 3/18 Delmarva – DE Gas Distribution Rates ComEd Electric Distribution Formula Rate Proposed Order Oct 19 Commission Order Expected Dec 9 Intervenor Direct Testimony Oct 16 Rebuttal Testimony Nov 16 Evidentiary Hearing Dec 11-20 Commission Order Expected Feb 14 Intervenor Direct Testimony Dec 6 Rebuttal Testimony Jan 12 Evidentiary Hearing Feb 20-22 Intervenor Direct Testimony Jan 16 Rebuttal Testimony Mar 5 Pepco Electric Distribution Rates - MD Evidentiary Hearings Sept 5-15 Commission Order Received Oct 20 Settlement approved by NJBPU Sept 22

37 Q3 2017 Earnings Release Slides Delmarva DE (Gas) Distribution Rate Case Filing 37 Docket No. 17-0978 Test Year January 1, 2017– December 31, 2017 Test Period 3 months actual and 9 months estimated Requested Common Equity Ratio 50.52% Requested Rate of Return ROE: 10.10%; ROR: 6.98% Proposed Rate Base (Adjusted) $348M Requested Revenue Requirement Increase $12.9M(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: January 16, 2018 • Rebuttal Testimony Due: March 5, 2018 • Evidentiary Hearings: April 24-26, 2018 • Initial Briefs Due: May 14, 2018 • Reply Briefs Due: May 29, 2018 • Commission Order Expected: Q3 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

38 Q3 2017 Earnings Release Slides Delmarva DE (Electric) Distribution Rate Case Filing 38 Docket No. 17-0977 Test Year January 1, 2017– December 31, 2017 Test Period 3 months actual and 9 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 4.6% 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 • Potential delay due to Staff and Division of the Public Advocate (DPA) joint motion to dismiss the application, which states that the increase of the requested increase to $31.2 million required additional time to review Procedural Schedule: • Intervenor Direct Testimony Due: December 6, 2017 • Rebuttal Testimony Due: January 12, 2018 • Evidentiary Hearings: February 20-22, 2018 • Initial Briefs Due: March 16, 2018 • Reply Briefs Due: March 30, 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

39 Q3 2017 Earnings Release Slides Delmarva MD (Electric) Distribution Rate Case Filing Formal Case No. 9455 Test Year October 1, 2016 – September 30, 2017 Test Period 7 months actual and 5 months estimated Requested Common Equity Ratio 50.68% Requested Rate of Return ROE: 10.10%; ROR: 7.05% Proposed Rate Base (Adjusted) (Updated on Sept. 28, 2017) $775M Requested Revenue Requirement Increase (Updated on Sept. 28, 2017) $21.6M(1) Residential Total Bill % Increase 1.8% 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: • Intervenor Direct Testimony Due: October 16, 2017 • Rebuttal Testimony Due: November 16, 2017 • Evidentiary Hearings: December 11 – 20, 2017 • Briefs due: January 9, 2018 • Commission Order Expected: February 14, 2018 (1) Amount represents adjusted requested revenue requirement filed on September 28, 2017

40 Q3 2017 Earnings Release Slides ComEd April 2017 Distribution Formula Rate 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. Common Equity Ratio ~46% for both the filing and reconciliation year ROE 8.40% for the filing year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium) and 8.34% for the reconciliation year (2016 30-yr Treasury Yield of 2.60% + 580 basis point risk premium – 6 basis points performance metrics penalty). For 2017 and 2018, the actual allowed ROE reflected in net income will ultimately be based on the average of the 30-year Treasury Yield during the respective years plus 580 basis point spread, absent any metric penalties Requested Rate of Return ~6.5% for both the filing and reconciliation years Rate Base(1) $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) Revenue Requirement Increase(1) $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. Timeline • 04/13/17 Filing Date • 240 Day Proceeding • ICC Order expected to be issued by December 9, 2017 The 2017 distribution formula rate filing established the net revenue requirement used to set the rates that will take effect in January 2018 after the Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing: • Filing Year: Based on 2016 costs and 2017 projected plant additions • Annual Reconciliation: For 2016, this amount reconciles the revenue requirement reflected in rates in effect during 2016 to the actual costs for that year. The annual reconciliation impacts cash flow in 2018 but the earnings impact has been recorded in 2016 as a regulatory asset. Given the retroactive ratemaking provision in the Energy Infrastructure Modernization Act (EIMA) legislation, ComEd net income during the year will be based on actual costs with a regulatory asset/liability recorded to reflect any under/over recovery reflected in rates. Revenue Requirement in rate filings impacts cash flow. (1) Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017

41 Q3 2017 Earnings Release Slides Pepco MD Distribution Rate Case Final Order Formal Case No. 9443 Per Commission Order Test Year May 1, 2016 – April 30, 2017 Test Period 8 months actual and 4 months estimated (Updated on August 24, 2017) Requested Common Equity Ratio 50.15% 50.15% Requested Rate of Return ROE: 10.10%; ROR: 7.74% ROE: 9.50%; ROR: 7.43% Proposed Rate Base (Adjusted) $1.7B $1.6B Requested Revenue Requirement Increase $67.0M $32.4M Residential Total Bill % Increase 5.6% 2.99% Notes • March 24, 2017, Pepco MD filed application with MDPSC seeking increase in electric distribution base rates • Normalization of tax benefits on pre-1981 removal costs • 8 month forward looking reliability and other plant additions from May 2017 through December 2017 ($13.3M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Intervenor Positions: • Office of People’s Council (OPC) revenue increase of $9.95M or $13.44M based on 8.75% or 9.0% ROE, respectively • Apartment and Office Building Association (AOBA) revenue increase of $24.76M based on 9.10% ROE • Commission Technical Staff (Staff) revenue increase of $25.76M based on 9.39% ROE • Commission Order Expected: October 20, 2017 • Order received on October 20th • Two months of post-test period reliability capital placed in service through June 2017 approved • Remaining deferred balance of storm costs for Sandy and Derecho to be amortized over 12 months • Expansion of test year to a minimum of 6 months of forecasted data was denied • Pepco’s proposal to normalize tax benefits for pre-1981 removal costs to be addressed in the next base rate case • Approximately $400K of AIP expense was excluded from recovery as a result of the Company not achieving its 2016 SAIFI merger target 41

42 Q3 2017 Earnings Release Slides Atlantic City Electric NJ Rate Case Final Order 42 BPU Docket No. ER17030308 Per Settlement Test Year August 1, 2016 – July 31, 2017 (Updated on July 14, 2017) Test Period 5 months actual and 7 months forecasted Stipulated Common Equity Ratio Requested 50.14% 50.47% Stipulated Rate of Return ROE: 10.10%; ROR: 7.83% ROE: 9.60% ROR: 7.60% Stipulated Rate Base (Adjusted) $1.4B $1.3B Stipulated Revenue Requirement Increase $72.6M $43.0M Stipulated Residential Total Bill % Increase 6.57% 4.03% Notes • March 30, 2017, Atlantic City Electric filed application with New Jersey Board of Public Utilities (NJBPU) seeking increase in electric distribution base rates • Recovery of investment in infrastructure to maintain and harden electric distribution system • Ratemaking adjustments to address declining sales • Proposal of a Non-Incremental System Renewal Recovery Charge for recovery of non- incremental reliability spend over four years (2018-2021) of $376M • Settlement Approved by NJBPU: September 22, 2017 • Rate Effective Date: October 1, 2017 • Approval for regulatory asset treatment of costs to achieve • Company agreed to withdraw its request to implement a System Renewal Recovery Charge • Company agreed to prepare proposal for phasing out accelerated reliability spending in Reliability Improvement Plan

43 Q3 2017 Earnings Release Slides Pepco DC Distribution Rate Case Final Order 43 Formal Case No. 1139 Per Commission Order Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.14% 49.14% Requested Rate of Return ROE: 10.60%; ROR: 8.00% ROE: 9.50%; ROR: 7.46% Proposed Rate Base (Adjusted) $1.7B $1.6B Requested Revenue Requirement Increase $77.5M(1) $36.9M Residential Total Bill % Increase 4.62% 2.52% Notes • June 30, 2016, Pepco filed application with District of Columbia Public Service Commission (DCPSC) seeking increase in electric distribution base rates Intervenor Positions: • Office of People’s Council (OPC) revenue increase of $25.8M based on 8.60% ROE • Apartment and Office Building Association (AOBA) revenue increase of $62.2M based on 9.25% ROE • Healthcare Council of the National Capital Area (HCNCA) revenue increase of $16.8M based on 8.75% ROE • District of Columbia Water and Sewer Authority (DC Water) revenue increase of $52.7M based on 9.10% ROE • July 25, 2017, DCPSC issued Final Order • Bill Stabilization Adjustment (BSA) remains unchanged • Approval to establish regulatory asset for costs to achieve (CTA) • Customer Base Rate Credit (CBRC) will offset monthly bill increases • $15M allocated to residential customers • $2.3M designated to certain small commercial customers • $6-7M reserved for disabled and senior citizens on fixed incomes in future rate cases • Recovery of $27.4M of AMI, direct load control and dynamic pricing regulatory assets to be amortized over 5 years (1) Revenue requirement includes changes in amortization expense, which has no impact on pre-tax earnings

44 Q3 2017 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures

45 Q3 2017 Earnings Release Slides Q3 2016 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 September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.25 $0.04 $0.13 $0.06 $0.18 ($0.13) $0.53 Mark-to-market impact of economic hedging activities (0.06) - - - - - (0.06) Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - - - 0.01 Merger commitments - - - - (0.04) 0.05 0.01 Long-Lived asset impairments 0.01 - - - - - 0.01 Plant retirements and divestitures 0.22 - - - - - 0.22 Cost management program 0.01 - - - - - 0.01 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 CENG noncontrolling interest 0.03 - - - - - 0.03 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.41 $0.20 $0.13 $0.06 $0.14 $(0.03) $0.91

46 Q3 2017 Earnings Release Slides Q3 2017 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 September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP (Loss) Earnings Per Share $0.32 $0.20 $0.12 $0.06 $0.16 ($0.00) $0.85 Mark-to-market impact of economic hedging activities (0.05) - - - - - (0.05) Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - (0.01) - - Long-lived asset impairments 0.03 - - - - - 0.03 Plant retirements and divestitures 0.08 - - - - - 0.08 Cost management program 0.01 - - - - - 0.01 Reassessment of state deferred income taxes 0.02 - - - - (0.04) (0.02) Bargain purchase gain (0.01) - - - - - (0.01) CENG noncontrolling interest 0.02 - - - - - 0.02 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.36 $0.19 $0.12 $0.07 $0.15 ($0.04) $0.85

47 Q3 2017 Earnings Release Slides Q3 2016 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. Nine Months Ended September 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.58 $0.32 $0.37 $0.20 ($0.10) $(0.37) $1.00 Mark-to-market impact of economic hedging activities 0.07 - - - - - 0.07 Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.02 - - - 0.04 0.04 0.10 Merger commitments - - - - 0.26 0.17 0.43 Long-lived asset impairments 0.11 - - - - - 0.11 Plant retirements and divestitures 0.37 - - - - - 0.37 Reassessment of state deferred income taxes 0.01 - - - - (0.01) - Cost management program 0.02 - - - - - 0.03 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 CENG noncontrolling interest 0.04 - - - - - 0.04 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.10 $0.48 $0.37 $0.20 $0.20 $(0.11) $2.24

48 Q3 2017 Earnings Release Slides Q3 2017 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share $0.51 $0.47 $0.35 $0.24 $0.38 $0.06 $2.01 Mark-to-market impact of economic hedging activities 0.10 - - - - - 0.10 Unrealized gains related to NDT fund investments (0.22) - - - - - (0.22) Amortization of commodity contract intangibles 0.03 - - - - - 0.03 Merger and integration costs 0.05 - - - (0.01) - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.15) Long-lived asset impairments 0.31 - - - - - 0.31 Plant retirements and divestitures 0.15 - - - - - 0.15 Reassessment of state deferred income taxes 0.02 - - - - (0.06) (0.04) Cost management program 0.02 - - - - - 0.03 Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) Asset retirement obligation - - - - - - - Tax settlements (0.01) - - - - - (0.01) Bargain purchase gain (0.25) - - - - - (0.25) CENG noncontrolling interest 0.08 - - - - - 0.08 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.76 $0.50 $0.35 $0.25 $0.31 ($0.12) $2.05 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

49 Q3 2017 Earnings Release Slides GAAP to Operating Adjustments • Exelon‟s 2017 adjusted (non-GAAP) operating earnings excludes the earnings effects of the following: − Mark-to-market adjustments from economic hedging activities − Unrealized gains 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 − Adjustments to reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI acquisitions − Impairments as a result of the ExGen Texas Power, LLC assets held for sale − Plant retirements and divestitures at Generation − Non-cash impact of the remeasurement of state deferred income taxes, related to changes in statutory tax rates and changes in forecasted apportionment − Costs incurred related to a cost management program − Certain adjustments related to Exelon’s like-kind exchange tax position − Non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units − Benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests − The excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition − Generation’s noncontrolling interest, primarily related to CENG exclusion items

50 Q3 2017 Earnings Release Slides (1) All amounts rounded to the nearest $25M (2) Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. (3) Reflects impact of operating adjustments on GAAP EBITDA (4) Includes other adjustments as prescribed by S&P (5) Reflects present value of net capacity purchases (6) Reflects present value of minimum future operating lease payments (7) Reflects after-tax unfunded pension/OPEB (8) Includes non-recourse project debt (9) Applies 75% of excess cash against balance of LTD (10) Reflects removal of EGTP (11) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018 YE 2017 Exelon FFO Calculation ($M) (1,2,10,11) GAAP Operating Income $3,500 Depreciation & Amortization $3,350 EBITDA $6,850 +/- Non-operating activities and nonrecurring items(3) $450 - Interest Expense ($1,450) + Current Income Tax (Expense)/Benefit $325 + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $350 = FFO (a) $7,600 YE 2017 Exelon Adjusted Debt Calculation ($M) (1,2,10) Long-Term Debt (including current maturities) $32,050 Short-Term Debt $1,125 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $875 + Pension/OPEB Imputed Debt(7) $4,100 - Off-Credit Treatment of Debt(8) ($1,725) - Surplus Cash Adjustment(9) ($600) +/- Other S&P Adjustments(4) ($650) = Adjusted Debt (b) $35,525 YE 2017 Exelon FFO/Debt (1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

51 Q3 2017 Earnings Release Slides YE 2017 ExGen Net Debt Calculation ($M) (1,3) Long-Term Debt (including current maturities) $8,775 Short-Term Debt $350 - Surplus Cash Adjustment ($300) = Net Debt (a) $8,825 YE 2017 Book Debt / EBITDA Net Debt (a) = 3.1x Operating EBITDA (b) (1) All amounts rounded to the nearest $25M (2) Reflects impact operating adjustments on GAAP EBITDA (3) Reflects removal of EGTP (4) Reflects delay in Illinois ZEC revenue recognition from 2017 to 2018 YE 2017 ExGen Operating EBITDA Calculation ($M) (1,3,4) GAAP Operating Income $775 Depreciation & Amortization $1,375 EBITDA $2,150 +/- Non-operating activities and nonrecurring items(2) $725 = Operating EBITDA (b) $2,875 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M) (1,3) Long-Term Debt (including current maturities) $8,775 Short-Term Debt $350 - Surplus Cash Adjustment ($300) - Nonrecourse Debt ($1,925) = Net Debt (a) $6,900 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.6x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M) (1,3,4) GAAP Operating Income $775 Depreciation & Amortization $1,375 EBITDA $2,150 +/- Non-operating activities and nonrecurring items(2) $725 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,625

52 Q3 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations (1) ACE, Delmarva, and Pepco represents full year of earnings Q3 2017 Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP) (1) $85 $114 $210 $1,281 $1,690 Operating Exclusions ($23) ($12) ($25) $34 ($25) Adjusted Operating Earnings (1) $63 $103 $185 $1,315 $1,665 Average Equity $1,061 $1,323 $2,419 $12,750 $17,554 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.9% 7.8% 7.7% 10.3% 9.5% Q2 2017 Operating ROE Reconciliation ($M)(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP) (1) $91 $127 $203 $1,132 $1,548 Operating Exclusions ($25) ($32) ($29) $186 $105 Adjusted Operating Earnings (1) $66 $95 $174 $1,318 $1,653 Average Equity $1,039 $1,300 $2,390 $12,308 $17,038 Operating ROE (Adjusted Operating Earnings/Average Equity) 6.4% 7.3% 7.3% 10.7% 9.7%

53 Q3 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations 2017 Adjusted Cash from Ops Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $1,375 $750 $775 $1,175 $3,400 ($250) $7,225 Other cash from investing activities - - - - ($275) - ($275) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $200 - $200 Adjusted Cash Flow from Operations $1,025 $750 $775 $1,175 $3,350 $75 $7,150 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $825 $175 $150 $125 ($300) $400 $1,375 Dividends paid on common stock $425 $300 $200 $325 $650 ($675) $1,225 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,600 $475 $350 $450 $350 ($625) $2,625 Exelon Total Cash Flow Reconciliation(1) 2017 GAAP Beginning Cash Balance $650 Adjustment for Cash Collateral Posted $400 Adjusted Beginning Cash Balance(3) $1,050 Net Change in Cash (GAAP)(2) $400 Adjusted Ending Cash Balance(3) $1,450 Adjustment for Cash Collateral Posted ($625) GAAP Ending Cash Balance $825 (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

54 Q3 2017 Earnings Release Slides GAAP to Non-GAAP Reconciliations 2017-2020 ExGen Free Cash Flow Calculation ($M)(1) Cash from Operations (GAAP) $15,150 Other Cash from Investing and Activities ($650) Baseline Capital Expenditures (4) ($4,025) Nuclear Fuel Capital Expenditures ($3,625) Free Cash Flow before Growth CapEx and Dividend $6,825 ExGen Adjusted O&M Reconciliation ($M)(1) 2017 2018 2019 2020 GAAP O&M $6,325 $5,300 $5,150 $5,025 Decommissioning(2) 25 50 50 50 TMI Retirement (75) - - - EGTP Impairment (450) - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (425) (325) (325) (325) O&M for managed plants that are partially owned (425) (425) (400) (425) Other (125) (25) (25) (25) Adjusted O&M (Non-GAAP) $4,850 $4,600 $4,450 $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