EEI Financial Conference November 2017

2 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 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 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 45 of this presentation.

5 Exelon: An Industry Leader Note: All numbers reflect year-end 2016; revenue accounts for PHI as of the merger effective date of March 24, 2016 through December 31, 2016.

6 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

7 Exelon Utilities Overview Note: All numbers reflect year-end 2016; revenue number accounts for PHI revenue as of March 24, 2016 merger date.

8 Exelon Utilities are an Industry Leader 15.217.719.620.2 23.724.925.0 31.732.435.1 50.0 57.0 PEG FE D ETR XEL EIX ED EXC PCG AEP SO DUK Total Utility Rate Base ($B)(1) Total Capital Expenditures 2017-2019 ($B)(1) 6.9 10.210.410.911.112.0 14.317.3 18.0 22.125.5 3 .9 SO DUK FE PEG ETR D ED XEL EIX AEP PCG EXC(2) US Utility Customers (millions) 3.1 4.24.84.95.05.1 5.45.56.0 6.8 8.99.29.8 10.0 ETR PEG ED NEE D EIX PCG EXC AEP XEL FE SRE DUK SO Source: Company Filings (1) Includes utility and generation (2) $23B includes $15.2B of utility capital expenditures and $6.9B of generation capital expenditures

9 Our Capital Plan Drives Stable Earnings Growth Capital Expenditures ($M) Over $20B of capital is being invested at utilities from 2017-2020 to improve reliability 2,200 2,025 1,675 1,775 925 950 975 875 775 800 775 750 1,375 1,400 1,350 1,425 2019E 4,775 2018E 5,175 2020E 4,825 2017E 5,275 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) 11.9 13.2 14.0 14.8 15.5 5.3 5.7 6.1 6.5 6.9 6.2 6.6 7.0 7.4 7.8 8.3 8.9 9.4 9.9 10.5 +6.5% 2020E 40.8 2019E 38.6 2018E 36.6 2017E 34.4 2016E 31.7 PHI ComEd PECO BGE

10 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

11 Proven Track Record of Improving Operational Performance Operations Metric At CEG Merger (2012) 2015 Q3 2017 BGE ComEd PECO PHI 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 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(2) 23rd 2nd 2nd 18th Q1 Q2 Q3 Q4 Performance Quartiles Exelon Utilities has identified and transferred best practices at each of its utilities to improve operating performance in areas such as: • System Performance • Emergency Preparedness • Corrective and Preventive Maintenance (1) 2.5 Beta SAIFI is YE projection (2) Ranking based on results of five key industry performance indicators – CAIDI, SAIFI, Safety, Customer Satisfaction, and Cost per Customer

12 Formulaic Mechanisms Cover Bulk of Rate Base Growth 2.1 1.1 1.3 9.0 0.7 2.3 0.9 0.8 Total 9.0 2020E 2.1 2019E 2.0 2018E 2.1 (0.1) 2017E 2.8 Of the approximately $9.0 billion of rate base growth Exelon Utilities forecasts over the next 4 years, ~75% will be recovered through existing formula and tracker mechanisms Rate Base Growth Breakout 2017-2020 ($B)(1) 6.7 2.3 Tracker/Formula Rate Base Rate Case Note: Numbers may not add due to rounding (1) Assumes PECO transmission formula rate beginning in 2018; base rate base decrease due to reclassification of transmission rate base growth at PECO

13 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%.

14 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

15 Exelon Utilities EPS Growth of 6-8% to 2020 $0.00 $1.70 $1.90 $1.60 $1.50 $1.80 $1.40 $2.00 $2.10 $1.80 2017E $1.90 $1.70 2019E $2.05 2020E 2018E $1.60 $1.50 U ti lit y O p erat in g E a rnin g s Rate base growth combined with PHI ROE improvement drives EPS growth $1.40 $1.75 Exelon Utilities Operating Earnings 2017-2020 Note: Reflects GAAP operating earnings except for 2017. 2017 GAAP EPS range would be $1.35 to $1.65. 2017 adjusted (non-GAAP) operating earnings include adjustments to exclude $0.05 for merger commitments and integration costs. Includes after-tax interest expense held at Corporate for debt associated with existing utility investment.

16 Exelon Generation Overview Note: All numbers reflect year-end 2016

17 Constellation Overview Note: All numbers reflect year-end 2016 (1) As calculated based on the national average generation supply mix used in EPA eGRID2014.

18 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 19 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

19 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

20 Forward Market Liquidity Total calendar peak traded volumes for the rolling 5-year window have been trending lower over the past year Calendar peak traded volumes beyond prompt year +1 account for less than 10% of total traded volumes * Please note that hedging strategy utilizes various price points (i.e. NIHUB, ERCOT), channels to market (i.e. Origination, Mid- Marketing, Retail, OTC), products (i.e. calendar, seasonal), and other exchanges July 2016 September 2017 Overall liquidity is declining Limited liquidity in the outer years 3% 2% 10% 43% 43% 0% 1% 12% 29% 58% September 2016 PJM West Hub Calendar Peak Traded Volumes(1) (by year) September 2017 PJM West Hub Calendar Peak Traded Volumes(1) (by year) (1) Total monthly traded volumes for rolling prompt year + 4 years on ICE and NASDAQ Exchanges only Prompt+4 Prompt+3 Prompt+2 Prompt+1 Prompt yr

21 Exelon’s Policy Priorities

22 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

23 ZEC Updates New York ZEC Legal Challenges IL 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 due December 1 • Oral arguments will then follow State Case: • Motions to dismiss procedural challenges filed in NY State court were briefed in 1Q17 • The court heard oral arguments on June 19 • Currently awaiting decision; next step determined by outcome • 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 due December 12 • Oral arguments will then follow

24 Exelon Policy Priorities  Create support for current challenged plants through federal and state initiatives  Support the ultimate pricing of carbon in the market on a regional or national level Modernize Utility Ratemaking to Ensure Appropriate Recovery Secure Proper Policies to Enable Innovative Technologies Recognize the Value of Zero-Carbon Electricity Regulatory and policy structure that supports clean, affordable and reliable options for all customers  Invest in infrastructure that provides customer benefit through grid resiliency and efficiency  Ensure fair rate structures to support new technologies  Providing new technologies to respond to customer needs  Open adjacent customer facing markets to sales and services

25 Our Carbon Policy Principles • Exelon believes in our nation’s ability to transition the generation fleet to a zero-carbon future while maintaining affordable and reliable electric service for consumers • For the foreseeable future, the most cost-effective carbon solution for our customers will be the continued operation of our nation’s nuclear fleet • Exelon believes competitive markets produce superior results for consumers and drive innovation. However, those markets do not currently incorporate appropriate pricing for environmental attributes. • Exelon is pursuing a two-part strategy for moving toward a more competitive treatment of CO2 emissions: o First, we must maintain nuclear units that provide a cost-effective form of CO2 abatement. The New York ZEC program demonstrates that as long as the clean energy payment required to maintain operations at existing nuclear units is lower than the social cost of CO2 emissions and the cost of CO2 abatement being paid to other zero carbon resources, maintaining nuclear capacity should be selected as the most competitive source of CO2 abatement. o Second, we must continue to work toward a technology neutral price of CO2 abatement. Exelon is pursuing approaches to reflect a uniform price on CO2 in wholesale markets as an eventual substitute for technology-specific subsidies. As these approaches are phased in, the ZEC programs have been designed to automatically reduce ZEC payments in response to higher energy prices.

26 Financial Overview

27 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

28 ~($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

29 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

30 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

31 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

32 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

33 Recognition for Stewardship and Employee Engagement Supplier Diversity: Exelon is the only utility and energy company to be inducted into the Billion Dollar Roundtable, which recognizes corporations that have achieved spending of $1 billion with minority and women- owned suppliers; our 2016 spend was nearly $2B Civic 50: Points of Light named Exelon utility sector leader in its annual ranking of the nation’s most community-minded public and private companies Top 50 Companies for Diversity: National recognition from DiversityInc, first year in Top 50 after being named a DiversityInc “Top Utility” in 2015 and 2016 Best Places to Work in 2017: Ranked No. 18 on Indeed.com survey of Fortune 500 companies based on employee reviews CEO Action for Diversity & Inclusion™: Joined 150 leading companies in the largest CEO-driven business commitment to advance diversity and inclusion Top 50 Most Energy-Efficient Utilities: American Council for an Energy-Efficient Economy ranks BGE and ComEd in the top 10 with PECO also making the list Lowest Carbon Emissions: 2017 Air Emissions Benchmarking Report notes Exelon’s generation fleet had the lowest carbon dioxide emissions of the top 20 privately held and investor-owned energy producers HeForShe: In continuing its commitment to gender equality, Exelon joined the United Nations HeForShe campaign, which provides a platform on which men can engage and become change agents for gender equality

34 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

35 Appendix

36 Exelon Debt Maturity Profile(1) ,594 312 500 910 800 833 500 850 360 763 295 175 1,430 675 700 600 650 1,200 18597 788 350 900 258 1,023 2,512 623 700 750741 833 750 807 1,150 300 900 2027 2026 2025 2024 2023 2019 2018 2017 26 2022 2021 1,189 2020 2041 1,400 2042 2044 2043 2045 1,225 1,275 2046 2047 2038 2040 2039 2036 2037 2035 2034 2033 2032 2031 78 2030 2029 53 2028 PHI Holdco ExCorp EXC Regulated ExGen Exelon’s weighted average LTD maturity is approximately 14 years (1) ExGen debt includes legacy CEG debt; Excludes securitized debt and non-recourse debt As of 9/30/17 ($M) BGE 2.6B ComEd 7.9B PECO 3.1B PHI 5.9B ExGen 9.5B HoldCo 6.3B Consolidated 35.3B LT Debt Balances (as of 9/30/17)

37 PJM Capacity Revenues(1,2,3) (1) Revenues reflect capacity cleared in Base, CP transitional & incremental auctions and are for calendar years (2) Revenues reflect owned and contracted generation (3) Reflects 50.01% ownership at CENG (4) Volumes at ownership and rounded $1,300 $1,200 $1,100 $1,000 $900 $800 $700 $600 $500 $400 $300 $200 $100 $0 $180 $170 $160 $150 $140 $130 $120 $110 $100 $90 $80 $70 $60 $50 $1,125 2018 $1,300 2017 $1,100 2016 $1,125 2019 2020 $1,000 Revenues ($ Million) Calendar weighted avg. price ($/Mw-day) R e ve nu e s ($ M ) C ap a cit y P ri c e ( $ / M W -d ) Capacity Market: PJM Cleared Volumes (MW)(4) CP Price Base Price CP Price Comed Nuclear 6,925 $203 - $183 8,075 $188 Fossil/Other - $203 50 $183 - $188 Subtotal 6,925 50 8,075 EMAAC Nuclear 4,375 $120 - $100 4,350 $188 Fossil/Other 1,525 $120 1,675 $100 2,325 $188 Subtotal 5,900 1,675 6,675 SWMAAC Nuclear 850 $100 - $80 850 $86 Fossil/Other - $100 - $80 - $86 Subtotal 850 - 850 MAAC Nuclear - - - $86 Fossil/Other - - 225 $86 Subtotal - - 225 BGE Nuclear - $100 - $80 - $86 Fossil/Other 375 $100 225 $80 375 $86 Subtotal 375 225 375 Rest of RTO Nuclear - $100 - $80 - $77 Fossil/Other 275 $100 75 $80 - $77 Subtotal 275 75 - PJM Total Nuclear 12,150 - 13,275 Fossil/Other 2,175 2,025 2,925 Grand Total 14,325 2,025 16,200 2019/2020 2020/2021

38 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

39 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

40 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

41 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

42 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

43 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

44 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

45 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%

46 Appendix Reconciliation of Non-GAAP Measures

47 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

48 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

49 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

50 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.

51 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

52 (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

53 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

54 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%

55 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