Earnings Conference Call 2nd Quarter 2017 August 2, 2017 Exhibit 99.2

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 Second Quarter 2017 Quarterly Report on Form 10-Q (to be filed on August 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 17; and (2) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this press release. None of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation.

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, 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

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 33 of this presentation.

  Note: Amounts may not sum due to rounding * Refer to pages 3 and 4 for information regarding non-GAAP financial measures Strong 2nd Quarter Results * Q2 2017 EPS Results GAAP earnings were $0.09/share in Q2 2017 vs. $0.29/share in Q2 2016 Adjusted operating earnings* were $0.54/share in Q2 2017 vs. $0.65/share in Q2 2016, near the top end of our guidance range of $0.45-$0.55/share

Operating Highlights Operations Metric Q2 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 2.5 Beta SAIFI is YE projection Excludes Salem 2016 industry average Exelon Utilities Operational Metrics Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Q2 Nuclear Capacity Factor: 90.9%(2) Q2 average refueling outage duration of 24 days versus industry average of 36 days(3) Shortest refueling outage duration record set for Nine Mile Point 1 Strong performance across our Fossil and Renewable fleet: Q2 Renewables energy capture: 95.5% Q2 Power dispatch match: 99.0% BGE and ComEd are meeting 1st decile performance in CAIDI BGE’s CAIDI and SAIFI performance was best on record ComEd’s SAIFI performance was best on record Pepco identified in JD Power customer satisfaction study as one of the most improved utilities for 2017 vs 2016 Quartiles Q1 Q2 Q3 Q4

Key Developments from the Second Quarter ZEC Litigation Updates PHI Rate Case Progress PJM Capacity Auction TMI Shutdown Decision

Key Market Policy 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.” The plaintiffs are expected to appeal to the US Court of Appeals for the 2nd Circuit The 2nd Circuit will set the briefing schedule after the appeal is filed State Case: Motions to dismiss procedural challenges filed in NY State court were briefed in 1Q17 The court heard oral arguments on June 19, 2017 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 due Aug 28 Defendant-Respondents Response Brief due Sep 27 Reply Briefs due Oct 27 Expect oral argument to follow DOE Report and PJM Reforms DOE Energy Report On April 14, 2017, Secretary of Energy Rick Perry ordered a review of the U.S. electrical grid, to determine if current policies are hastening the retirement of baseload plants and threatening power system resilience and reliability. “Nuclear power is a key component of our all-of-the-above energy strategy. Zero emissions, always on.”– Secretary Rick Perry Proposed PJM Reforms Recognize value of resiliency by instituting operational reforms in which PJM would commit additional reserves to account for the consumer impact from the most significant potential disruption Refine price formation to recognize the critical contribution of all resources, including “baseload” nuclear resources

Q2 2017 Adjusted Operating EPS* Results Exelon Utilities Timing of O&M Exelon Generation Timing of O&M NDT realized gains(1) 2nd Quarter Adjusted Operating Earnings* Drivers Q2 2017 vs. Guidance of $0.45 - $0.55 $0.33 Note: Amounts may not sum due to rounding Gains related to unregulated sites

Q2 Adjusted Operating Earnings* Waterfall $0.54 ($0.16) Market Conditions(1) ($0.05) O&M Impact of Outages(2) $0.05 Zero Emission Credit Revenue(3) $0.03 Other $0.03 Absence of 2016 Rate Case Disallowances $0.01 Increased Distribution Rates ($0.01) Income Taxes ($0.01) Other $0.02 Increased Distribution Rates ($0.01) O&M Note: Amounts may not sum due to rounding Includes the unfavorable impact of the conclusion of the Ginna Reliability Support Services Agreement, lower realized energy prices and lower optimization in Generation’s natural gas portfolio Driven by higher planned outages in 2017; excludes Salem Reflects the impact of the New York Clean Energy Standard 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 ($0.01) 2016 Weather(4) $0.01 Rate base $0.01 U.S. Treasuries (ROE) ($0.01) Other $0.02 Income Taxes $0.01 O&M ($0.01) Weather & Load

YTD Adjusted Operating Earnings* Waterfall $1.19 ($0.17) Market Conditions(1) ($0.07) O&M Impact of Outages(2) ($0.07) Other O&M ($0.03) Capacity Pricing $0.05 Zero Emission Credit Revenue(3) $0.03 Increased Distribution Rates $0.03 Absence of 2016 Rate Case Disallowances $0.01 Decreased Storm Costs ($0.01) Depreciation & Amortization ($0.01) Income Taxes ($0.01) Other $0.05 Increased Distribution Rates $0.04 Other(5) Note: Amounts may not sum due to rounding Includes the unfavorable impacts of declining natural gas prices and lower optimization in Generation’s natural gas portfolio, the conclusion of the Ginna Reliability Support Services Agreement and lower realized energy prices, partially offset by the absence of oil inventory write downs that occurred in 2016 Driven by higher planned outages in 2017; excludes Salem Reflects the impact of the New York Clean Energy Standard 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 PHI reflects full six months of earnings in 2017 versus earnings from March 24, 2016 through June 30, 2016 $0.03 Rate Base $0.01 U.S. Treasuries (ROE) ($0.01) 2016 Weather & Load(4) ($0.01) Load & Depreciation

$2.50 - $2.80(2) ~($0.20) $0.60 - $0.70 $0.40 - $0.50 $0.30 - $0.40 $0.25 - $0.35 $1.05 - $1.15 $2.68(1) Reaffirming 2017 Adjusted Operating Earnings* Guidance 2016 results based on 2016 average outstanding shares of 927M 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not sum up to consolidated EPS guidance. Expect Q3 2017 Adjusted Operating Earnings* of $0.80 - $0.90 per share Key Year-Over-Year Drivers ExGen: Lower realized energy prices, partially offset by NY and IL ZEC revenues BGE: Higher D&A, partially offset by normalization of one time items and distribution revenue PHI: Full year of earnings and higher distribution and transmission revenue from investments to improve reliability PECO: Higher O&M for storms and higher D&A ComEd: Increased capital investments to improve reliability in distribution and transmission and higher U.S. Treasury yields

Trailing 12 Month ROE vs Allowed ROE Twelve Month Trailing Earned ROEs* (1) Note: Represents the period from 6/30/16 to 6/30/17 and reflects all lines of business (Electric Distribution, Gas Distribution, and Transmission) (1) Pepco DC Distribution allowed ROE is based on an authorized ROE of 9.4% for the rates that were in effect during the trailing twelve month period.  The order issued on 7/25/17 authorized an ROE of 9.5%.

Exelon Utilities Distribution Rate Case Summary Delmarva DE Electric Order Authorized Revenue Requirement Increase(1) $31.5M Authorized ROE 9.70% Common Equity Ratio N/A Order Received 5/23/17 Delmarva DE Gas Order Authorized Revenue Requirement Increase(1) $4.9M Authorized ROE 9.70% Common Equity Ratio N/A Order Received 6/6/17 Delmarva MD Order Authorized Revenue Requirement Increase(1) $38.3M Authorized ROE 9.60% Common Equity Ratio 49.10% Order Received 2/15/17 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 Filing Requested Revenue Requirement Increase(1) $68.6M Requested ROE 10.10% Requested Common Equity Ratio 50.15% Order Expected 10/20/17 ACE Filing Requested Revenue Requirement Increase(1) $72.6M Requested ROE 10.10% Requested Common Equity Ratio 50.14% Order Expected Q1 2018 Delmarva MD Filing Requested Revenue Requirement Increase(1) $27.0M 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 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017

Cleared 16.2 GW of generation capacity in 2020/2021 PJM base residual auction The bulk of cleared capacity was in the ComEd and EMAAC zones, which cleared above rest of RTO pricing at $188/MW-d Despite volatility in PJM capacity market, capacity revenues have met or exceeded $1B annually Updates: RPM Results and TMI Closure (1) Based on May 31, 2017, pricing and exclude decommissioning impacts PJM 2020/2021 Capacity Auction TMI Closure Exelon announced that it will retire TMI in September 2019, absent needed policy reforms Announcement comes after TMI failed to clear PJM base residual auctions for the third consecutive year Financial impact(1) of TMI retirement is annual accretive EPS impact of $0.04-$0.07 and cumulative cash flow impact of ~$225M through 2021

Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on June 30, 2017, market conditions 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. EGTP removal results in $100M reduction to gross margin in 2018 and 2019 with positive EPS impacts of $0.02-$0.03. TMI retirement results in $50M reduction in gross margin in 2019. Executed $200M of Power New Business in 2017 Reflects removal of EGTP(5) and TMI(5) Behind ratable hedging position reflects the fundamental upside we see in power prices ~11-14% behind ratable in 2018 when considering cross commodity hedges Recent Developments

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 July 2017 Overall liquidity is declining Limited liquidity in the outer years July 2016 PJM West Hub Calendar Peak Traded Volumes(1) (by year) July 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

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- Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment Current senior unsecured ratings as of July 26, 2017, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco All ratings have “Stable” outlook 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 Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* Reflects removal of EGTP ExGen Debt/EBITDA Ratio*(5,6) Exelon S&P FFO/Debt %*(1,4,6) Credit Ratings by Operating Company 18%-20% x x 3.0x Excluding Non-Recourse Book S&P Threshold

Innovation Expo Highlights Our 2017 Innovation Expo in Washington, D.C. showcased the latest advanced technology products and processes Exelon is deploying to deliver on our commitment to provide safe, reliable, affordable and clean energy Exelon employees, vendors and industry experts explored how technology can solve challenges affecting the energy industry and our customers at our biggest event to date

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 nuclear facilities had the lowest carbon dioxide emissions of the top 20 privately held and investor-owned energy producers

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

Additional Disclosures

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 Revenues ($M) Capacity Price ($/MW-d) Capacity Market: PJM

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 Plan to issue $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 $4.9B of free cash flow, including $1.4B at ExGen and $3.4B at the Utilities Creating value for customers, communities and shareholders Investing $6.0B, with $5.3B at the Utilities and $0.8B at ExGen All amounts rounded to the nearest $25M. Figures may not add due to rounding. Gross of posted counterparty collateral Excludes counterparty collateral activity Figures reflect cash CapEx and CENG fleet at 100% Other Financing includes expected changes in short-term debt, money pool borrowings, tax sharing from the parent, debt issue costs, CENG credit facility, tax equity cash flows, Renewable JV, and capital leases Financing cash flow excludes intercompany dividends and other intercompany financing activities ExGen Growth CapEx primarily includes Texas CCGTs, AGE, W. Medway, Retail Solar, and Retail Growth Dividends are subject to declaration by the Board of Directors Includes cash flow activity from Holding Company, eliminations, and other corporate entities

Exelon Generation Disclosures June 30, 2017

Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % Hedged 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 Strategic Policy Alignment Three-Year Ratable Hedging Ensure stability in near-term cash flows and earnings Bull / Bear Program Ability to exercise fundamental market views to create value within the ratable framework Hedge enough commodity risk to meet future cash requirements under a stress scenario Tenor aligns with customer preferences and market liquidity Multiple channels to market that allow us to maximize margins Cross-commodity hedging (heat rate positions, options, etc.) Delivery locations, regional and zonal spread relationships Aligns hedging program with financial policies and financial outlook Disciplined approach to hedging Large open position in outer years to benefit from price upside Modified timing of hedges versus purely ratable Establish minimum hedge targets to meet financial objectives of the company (dividend, credit rating) Credit Rating Capital & Operating Expenditure Dividend Capital Structure

Components of Gross Margin Categories 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 Open Gross Margin Generation Gross Margin at current market prices, including ancillary revenues, nuclear fuel amortization and fossils fuels expense MtM of Hedges (2) Mark-to-Market ( MtM ) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions “Power” New Business Retail, Wholesale planned electric sales “Non Power” Executed “Non Power” New Business 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) ) 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. Portfolio Management new business Mid marketing new business Retail, Wholesale executed gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Retail, Wholesale planned gas sales Energy Efficiency (4) BGE Home (4) Distributed Solar Portfolio Management / origination fuels new business Proprietary trading (3) Capacity and ZEC Revenues Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC)

ExGen Disclosures Gross margin categories rounded to nearest $50M Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on June 30, 2017, market conditions 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.

ExGen Disclosures 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%, 93.3% 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. Excludes EDF’s equity ownership share of CENG Joint Venture 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. 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. Spark spreads shown for ERCOT and New England 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.

ExGen Hedged Gross Margin* Sensitivities Based on June 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

ExGen Hedged Gross Margin* Upside/Risk Approximate Gross Margin* ($ million)(1,2,3) $8,200 $8,050 $8,450 $7,750 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 June 30, 2017 Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions 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. $6,850 $8,800

Illustrative Example of Modeling Exelon Generation 2018 Gross Margin* Mark-to-market rounded to the nearest $5 million

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense*(2,3) $8,675 $8,725 $8,300 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(150) $(225) $(200) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) $(425) $(400) $(400) Total Gross Margin* (Non-GAAP) $8,150 $8,100 $7,700 All amounts rounded to the nearest $25M 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. Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices Other Revenues reflects 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 Reflects the cost of sales of certain Constellation and Power businesses ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture 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 TOTI excludes gross receipts tax of $150M Excludes P&L neutral decommissioning depreciation 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)(1,6) 2017 Other(7) $150 Adjusted O&M* $(4,850) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization(9) $(1,100) Interest Expense(10) $(400) Effective Tax Rate 32.0%

Exelon Utilities Rate Case Filing Summaries

6/17 7/17 8/17 9/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - MD Pepco Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 10/17 11/17 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, and Delaware Public Service Commission and are subject to change 12/17 Commission Order Received July 25 ACE Electric Distribution Rates - NJ ComEd Electric Distribution Formula Rate Rebuttal Testimony Mid-July Intervenor Direct Testimony June 30 Rebuttal Testimony Aug. 1 Evidentiary Hearings Sept. 5-15 Rate Case Filed July 14 Commission Order Expected Oct. 20 Intervenor Direct Testimony Aug. 1 Rebuttal Testimony Sept. 6 Evidentiary Hearings Oct. 2-13 Hearings August 28 Proposed Order October 19 Commission Order Expected December 9

Delmarva DE (Electric) Distribution Rate Case Final Order The Settlement is a partial “black box settlement” meaning that the Settling Parties have agreed to some terms in the Settlement, but not others. No adjusted rate base or earnings were documented. As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $29.6M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0649 Approved Black Box Settlement Test Year 2015 Calendar Year Test Period 12 months actual Authorized Common Equity Ratio 49.44% Authorized Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base(1) $839M Authorized Revenue Requirement Increase(2,3) $60.2M $31.5M Revenue increase includes approx. $7.5M of new depreciation and amortization expense Residential Total Bill % Increase 7.25% 4.80% Notes 5/17/16 DPL DE filed application with the Delaware Public Service Commission (DPSC) seeking increase in electric distribution base rates 18 month forward-looking reliability and other plant additions from January 2016 through June 2017 ($8.4M of Revenue Requirement based on 10.60% ROE) included in revenue requirement request Includes the Pay as You Go Program, a proposed pilot program that would be cooperatively designed to use the capability of the AMI meters to offer a voluntary pre-paid metering option for customers 3/8/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Recovery of $28.6M of direct load control and dynamic pricing regulatory assets to be amortized over 10 years Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Actual synergy savings and costs to achieve will be reviewed in next base rate proceeding Commission Approved Settlement: 5/23/17 Rates effective June 1; no interim rate refunds

Delmarva DE (Gas) Distribution Rate Case Final Order The Settlement is a partial “black box settlement” meaning that the Settling Parties have agreed to some terms in the Settlement, but not others. No adjusted rate base or earnings were documented. As permitted by Delaware law, Delmarva Power implemented interim rate increases of $2.5 million on July 16, 2016, and implemented an incremental $10.4M on December 17, 2016, subject to refund Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings Docket # 16-0650 Approved Black Box Settlement Test Year 2015 Calendar Year Test Period 12 months actual Common Equity Ratio 49.44% Rate of Return ROE: 10.60%; ROR: 7.19% ROE: 9.70% Rate Base(1) $362M Revenue Requirement Increase(2,3) $22.2M $4.9M Revenue increase includes net reduction of $4.8M in new depreciation and amortization expense Residential Total Bill % Increase 10.40% 2.70% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in gas distribution base rates 4/6/17 Unanimous settlement filed with the DPSC New depreciation rates included in the revenue increase Incremental labor costs for the Interface Management Unit (IMU) battery replacement project deferred into a regulatory asset for review in a future proceeding Approval to establish regulatory asset for costs to achieve synergy savings, amortized over 5 years Actual synergy savings and costs to achieve will be reviewed against actuals in next base rate proceeding Commission approved settlement: 6/6/17 Rates effective July 1 Refund will be issued for amounts collected, under interim rates, in excess of $4.9M revenue requirement increase

Pepco DC Rate Case Final Order 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 $76.8M(1) $36.9M EBIT impact is currently estimated at $39M related to new items per the Order Residential Total Bill % Increase 4.62% 2.52% Notes 6/30/16 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 7/25/17 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

Pepco MD Rate Case Filing Formal Case No. 9443 Test Year May 1, 2016 – April 30, 2017 Test Period 8 months actual and 4 months estimated Requested Common Equity Ratio 50.15% Requested Rate of Return ROE: 10.10%; ROR: 7.74% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase(1) $68.6M Residential Total Bill % Increase 5.6% Notes 3/24/17 Pepco MD filed application with the Maryland Public Service Commission (MDPSC ) seeking increase in electric distribution base rates Size of ask is driven by Continued Investments in the electric distribution system to maintain and increase reliability and customer service 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 Company is seeking recovery of the restoration portion of the Supplemental Executive Retirement Plan (SERP) Procedural Schedule: Intervenor Direct Testimony Due: 6/30/17 Rebuttal Testimony Due: 8/1/17 Evidentiary Hearings: 9/5/17 – 9/15/17 Brief Due: 10/3/17 Commission Order Expected: 10/20/17 Revenue requirement includes changes in depreciation and amortization expense, which have no impact on pre-tax earnings. Updated June 7, 2017.

Atlantic City Electric NJ Rate Case Filing BPU Docket No. ER17030308 Test Year August 1, 2016 – July 31, 2017 Test Period 5 months actual and 7 months estimated Requested Common Equity Ratio 50.14% Requested Rate of Return ROE: 10.10%; ROR: 7.83% Proposed Rate Base (Adjusted) $1.4B Requested Revenue Requirement Increase(1) $72.6M Residential Total Bill % Increase 6.57% Notes 3/30/17 ACE filed application with the New Jersey Board of Public Utilities (NJBPU) seeking increase in electric distribution base rates Recovery of investment in infrastructure to maintain and harden the electric distribution system Ratemaking adjustments to address declining sales 8 month forward-looking reliability and other plant additions from August 2017 through March 2018 ($8.4M of Revenue Requirement based on 10.10% ROE) included in revenue requirement request Proposal of a Non-Incremental System Renewal Recovery Charge for recovery of non-incremental reliability spend over four years (2018-2021) of $376 million. Procedural Schedule: Settlement Meeting: 7/17/17 Intervenor Direct Testimony Due: 8/1/17 Rebuttal Testimony Due: 9/6/17 Evidentiary Hearings: 10/2/17 – 10/13/17 Commission Order Expected: March 2018 (1) Updated on July 14, 2017

Delmarva Power & Light MD 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) $791M Requested Revenue Requirement Increase $27.0M Residential Total Bill % Increase 1.9% Notes 7/14/17 DPL MD filed application with the Maryland Public Service Commission (MDPSC ) seeking increase in electric distribution base rates Size of ask is driven by continued investments in the electric distribution system to maintain and increase reliability and customer service 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 Requested year end rate base treatment ($4.1M of Revenue Requirement based on 10.10% ROE) Commission Order expected: 2/14/18

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 on FRU 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. Amount represents ComEd’s position filed in Rebuttal testimony on July 21, 2017

Appendix Reconciliation of Non-GAAP Measures

Q2 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 June 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.00 $0.16 $0.11 $0.03 $0.06 ($0.06) $0.29 Mark-to-market impact of economic hedging activities 0.20 - - - - - 0.20 Unrealized gains related to NDT fund investments (0.03) - - - - - (0.03) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-Lived asset impairments 0.02 - - - - - 0.02 Plant retirements and divestitures 0.14 - - - - - 0.14 Cost management program - - - - - - 0.01 CENG noncontrolling interest 0.01 - - - - - 0.01 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.35 $0.16 $0.11 $0.03 $0.06 $(0.06) $0.65

Q2 2017 QTD GAAP EPS Reconciliation (continued) Three Months Ended June 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP (Loss) Earnings Per Share ($0.27) $0.13 $0.09 $0.05 $0.07 $0.02 $0.09 Mark-to-market impact of economic hedging activities 0.12 - - - - - 0.12 Unrealized gains related to NDT fund investments (0.05) - - - - - (0.05) Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Merger and integration costs 0.01 - - - - - 0.01 Long-lived asset impairments 0.29 - - - - - 0.29 Plant retirements and divestitures 0.07 - - - - - 0.07 Cost management program - - - - - - 0.01 Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) CENG noncontrolling interest 0.02 - - - - - 0.02 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.22 $0.15 $0.10 $0.05 $0.07 $(0.03) $0.54 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

Q2 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. Six Months Ended June 30, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.31 $0.28 $0.25 $0.14 ($0.28) $(0.23) $0.48 Mark-to-market impact of economic hedging activities 0.12 - - - - - 0.12 Unrealized gains related to NDT fund investments (0.07) - - - - - (0.07) Merger and integration costs 0.02 - - - 0.04 0.04 0.09 Merger commitments - - - - 0.30 0.12 0.43 Long-lived asset impairments 0.10 - - - - - 0.10 Plant retirements and divestitures 0.14 - - - - - 0.14 Reassessment of state deferred income taxes 0.01 - - - - (0.01) - Cost management program 0.02 - - - - - 0.02 CENG noncontrolling interest 0.02 - - - - - 0.02 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.69 $0.28 $0.25 $0.14 $0.06 $(0.08) $1.33

Q2 2017 YTD GAAP EPS Reconciliation (continued) Six Months Ended June 30, 2017 ExGen ComEd PECO BGE PHI Other Exelon 2017 GAAP Earnings (Loss) Per Share $0.19 $0.28 $0.23 $0.18 $0.22 $0.06 $1.15 Mark-to-market impact of economic hedging activities 0.15 - - - - - 0.15 Unrealized gains related to NDT fund investments (0.15) - - - - - (0.15) Amortization of commodity contract intangibles 0.02 - - - - - 0.02 Merger and integration costs 0.04 - - - - - 0.04 Merger commitments (0.02) - - - (0.06) (0.06) (0.15) Long-lived asset impairments 0.29 - - - - - 0.29 Plant retirements and divestitures 0.07 - - - - - 0.07 Reassessment of state deferred income taxes - - - - - (0.02) (0.02) Cost management program 0.01 - - - - - 0.01 Tax settlements (0.01) - - - - - (0.01) Bargain purchase gain (0.24) - - - - - (0.24) Like-kind exchange tax position - 0.02 - - - (0.05) (0.03) CENG noncontrolling interest 0.06 - - - - - 0.06 2017 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.40 $0.30 $0.23 $0.18 $0.15 ($0.08) $1.19 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

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 of certain wind projects at Generation and 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 a change in the statutory tax rate Costs incurred related to a cost management program 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 Certain adjustments related to Exelon’s like-kind exchange tax position Generation’s non-controlling interest, primarily related to CENG exclusion items

All amounts rounded to the nearest $25M Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. Reflects impact of operating adjustments on GAAP EBITDA Includes other adjustments as prescribed by S&P Reflects present value of net capacity purchases Reflects present value of minimum future operating lease payments Reflects after-tax unfunded pension/OPEB Includes non-recourse project debt Applies 75% of excess cash against balance of LTD YE 2017 Exelon FFO Calculation ($M)(1,2) GAAP Operating Income $3,450 Depreciation & Amortization $3,375 EBITDA $6,825 +/- Non-operating activities and nonrecurring items(3) $550 - Interest Expense ($1,450) + Current Income Tax (Expense)/Benefit $25 + Nuclear Fuel Amortization $1,075 +/- Other S&P Adjustments(4) $375 = FFO (a) $7,400 YE 2017 Exelon Adjusted Debt Calculation ($M)(1,2) Long-Term Debt (including current maturities) $32,025 Short-Term Debt $1,225 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $875 + Pension/OPEB Imputed Debt(7) $3,450 - Off-Credit Treatment of Debt(8) ($1,725) - Surplus Cash Adjustment(9) ($550) +/- Other S&P Adjustments(4) $275 = Adjusted Debt (b) $35,925 YE 2017 Exelon FFO/Debt(1,2) FFO (a) = 21% Adjusted Debt (b) GAAP to Non-GAAP Reconciliations

YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $8,875 Short-Term Debt $375 - Surplus Cash Adjustment ($300) = Net Debt (a) $8,950 YE 2017 Book Debt / EBITDA Net Debt (a) = 2.9x Operating EBITDA (b) All amounts rounded to the nearest $25M Reflects impact of operating adjustments on GAAP EBITDA YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $775 Depreciation & Amortization $1,400 EBITDA $2,175 +/- Non-operating activities and nonrecurring items(2) $875 = Operating EBITDA (b) $3,050 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $8,875 Short-Term Debt $375 - Surplus Cash Adjustment ($300) - Nonrecourse Debt ($1,900) = Net Debt (a) $7,050 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.5x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $775 Depreciation & Amortization $1,400 EBITDA $2,175 +/- Non-operating activities and nonrecurring items(2) $875 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,800

GAAP to Non-GAAP Reconciliations ACE, Delmarva, and Pepco represents full year of earnings All amounts rounded to the nearest $25M. Items may not sum due to rounding. Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* Operating ROE Reconciliation ($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 $17,038 Operating ROE (Adjusted Operating Earnings/Average Equity) 6.4% 7.3% 7.3% 10.7% 9.7% ExGen Adjusted O&M Reconciliation ($M)(2) 2017 GAAP O&M $6,300 Decommissioning(3) 25 TMI Retirement (100) EGTP Impairment (425) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) (425) O&M for managed plants that are partially owned (425) Other (100) Adjusted O&M (Non-GAAP) $4,850

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) $1,150 $750 $700 $1,150 $3,450 ($250) $6,975 Other cash from investing activities - - - - ($275) - ($275) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $225 - $225 Adjusted Cash Flow from Operations $800 $750 $700 $1,150 $3,425 $100 $6,950 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $1,000 $175 $200 $175 ($275) $350 $1,625 Dividends paid on common stock $425 $300 $200 $325 $650 ($650) $1,250 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,775 $475 $400 $500 $375 ($650) $2,875 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) $375 Adjusted Ending Cash Balance(3) $1,425 Adjustment for Cash Collateral Posted ($625) GAAP Ending Cash Balance $775 All amounts rounded to the nearest $25M. Items may not sum due to rounding. 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%. Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity