Peco Energy 8-K Results of Operations and Financial Condition

Earnings Conference Call 4th Quarter 2016 February 8, 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 (PHI), 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 2015 Annual Report on Form 10-K in (a) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 23; (2) PHI’s 2015 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 16; (3) Exelon’s Third Quarter 2016 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 (4) 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 presentation. 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 (non-GAAP) operating earnings, adjusted (non-GAAP) operating and maintenance expense, total gross margin, and adjusted cash flow from operations (non-GAAP) or free cash flow. Adjusted (non-GAAP) 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 costs, certain costs incurred associated with the PHI acquisition, merger commitments related to the settlement of the PHI acquisition, the impairment of certain long-lived assets, plant retirements and divestitures, costs related to the cost management program, the non-controlling interest in CENG, and other items as set forth in the reconciliation in the Appendix. Adjusted (non-GAAP) operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation 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 (non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, the operating services agreement with Fort Calhoun, variable interest entities and net of direct cost of sales for certain Constellation businesses. Adjusted cash flow from operations (non-GAAP) or free cash flow 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. Due to the forward-looking nature of any forecasted non-GAAP measures, information to reconcile the forecast adjusted (non-GAAP) measures to the most directly comparable GAAP measure is not 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 measure 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. Reconciliations of these non-GAAP measures to the most comparable GAAP measures are provided in the footnotes, appendices and attachments to this presentation.

2016 Milestone Accomplishments Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Financial Delivered FY 2016 GAAP earnings of $1.22 and adjusted operating earnings of $2.68 per share, within our guidance range (1) Implemented 2.5% annual dividend growth strategy through 2018 Growth Completed acquisition of ConEd Solutions Regulatory & Policy Employees & Community IL and NY ZEC Programs will preserve five nuclear plants at risk of closure Pending acquisition of the FitzPatrick nuclear power station IL Legislation provides ComEd a fair return on energy efficiency investments that benefit our customers and also extends EIMA formula rate to 2022 Commitment to our workforce through best in industry parental leave program and first utility to sign the Equal Pay pledge Exelon employees donated 171,341 hours to volunteer initiatives and Exelon donated $46M to our local communities Completed distribution rate cases providing $317M in revenue increases with another $80M for FERC transmission Completed the acquisition of PHI, adding $8.3B of rate base Invested $5.2B of capital to improve reliability at our regulated Utilities excluding the merger Named as the only Utility on the Fortune 100 list Exelon’s diverse supplier spend reached $1.9B in 2016, up 202% since 2011

Best in Class Utility Operations Comments Operationally, the utilities ended the year with strong results across key metrics BGE, ComEd, and PECO achieved 1st decile performance in Customer Satisfaction Index (CSI) that was the best ever performance for each utility PECO achieved 1st decile performance in OSHA Recordable Rate ComEd and PECO achieved 1st decile performance for outage frequency. ComEd’s results were best on record and best in class. PHI outage frequency performance was best ever on record Operations Metric 2016 BGE PECO ComEd PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction N/A Service Level % of Calls Answered in <30 sec Abandon Rate Gas Operations Percent of Calls Responded to in <1 Hour No Gas Operations 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 Customer Care Exelon Utilities Operational Metrics Quartiles Q1 Q2 Q3 Q4

Best in Class at ExGen and Constellation Exelon Generation Operational Metrics Continued best in class performance across our Nuclear fleet: Capacity Factor of 94.6% is the highest ever for Exelon Most power ever generated at 153M MWh(1) All-time shortest refueling outage duration average of 22 days Strong performance across our Fossil and Renewable fleet: Renewables energy capture: 95.6% Power dispatch match: 97.2% Constellation Metrics Closed on ConEdison Solutions transaction, adding more than 560,000 customers (1) Reflects generation output at ownership 77% retail power customer renewal rate 28% power new customer win rate 25 month average power contract term Average customer duration of more than 5 years Stable Retail Margins 91% natural gas customer retention rate

  Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Amounts may not add due to rounding Strong 2016 Financial Results 2016 EPS Results(1,2) Adjusted (non-GAAP) operating earnings full year drivers versus guidance: Utilities Weather Lower O&M Exelon Generation Lower cost to serve Nuclear Generation Output

$2.50 - $2.80(2) ~($0.20) $1.05 - $1.15 $0.60 - $0.70 $0.40 - $0.50 $0.30 - $0.40 $0.25 - $0.35 $2.68(1) 2017 Adjusted Operating Earnings Guidance 2016 results based on 2016 average outstanding shares of 927M. Refer to Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 2017 earnings guidance based on expected average outstanding shares of 949M. Earnings guidance for OpCos may not add up to consolidated EPS guidance. Refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. Expect Q1 2017 Adjusted Operating Earnings of $0.55 - $0.65 per share Key Year-Over-Year Drivers 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 PECO: Higher O&M for storms and higher D&A for CapEx ComEd: Increased capital investments to improve reliability in distribution and transmission and higher U.S. Treasury yields ExGen: Lower realized energy prices, partially offset by NY and IL ZEC revenues

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 Note: CapEx numbers are rounded to nearest $25M and numbers may not add due to rounding. Rate base reflects year-end estimates. Rate Base ($B)

Formulaic Mechanisms Cover Bulk of Rate Base Growth 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 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

Weighted Average Allowed vs Earned ROE Comparison Twelve Month Trailing Earned ROEs(1,2) Operating ROE is calculated using operating net income divided by simple average equity for the period 12/31/15 – 12/31/16.  The operating net income is reflective of all lines of business (Electric Distribution, Gas Distribution, Transmission).  For a reconciliation of operating ROE, which is a non-GAAP measure derived from adjusted operating earnings, please refer to slide 78 in the Appendix

Exelon Utilities Distribution Rate Case Summary ACE Electric Final Order Pepco MD Final Order Requested Revenue Requirement Increase(1) $52.5M Requested ROE 9.55% Requested Common Equity Ratio 49.55% Order Received 11/15/16 Delmarva DE Electric Filing Requested Revenue Requirement Increase(1) $60.2M Requested ROE 10.60% Requested Common Equity Ratio 49.44% Order Expected Q3 2017 Delmarva DE Gas Filing Requested Revenue Requirement Increase(1) $21.5M Requested ROE 10.60% Requested Common Equity Ratio 49.44% Order Expected Q3 2017 Delmarva MD Filing Requested Revenue Requirement Increase(1) $57M Requested ROE 10.60% Requested Common Equity Ratio 49.10% Order Expected 2/17/17 Pepco DC Filing Requested Revenue Requirement Increase(1) $76.8M Requested ROE 10.60% Requested Common Equity Ratio 49.14% Order Expected 7/25/17 ComEd Final Order Requested Revenue Requirement Increase(2) $127M Authorized ROE 8.64% Common Equity Ratio 46% Order Received 12/6/16 Revenue requirement includes changes in depreciation and amortization expense where applicable, which have no impact on pre-tax earnings Amounts represents the Illinois Commerce Commission’s approved revenue requirement amount in the December 6th Final Order. The ICC also ordered rehearing on one narrow topic that ComEd expects to result in a further reduction to the revenue requirement of $17.5M. On July 29, 2016, BGE received a PSC order on rehearing, which is reflected in the revenue requirement increase ComEd Authorized ROE is tied to the 30 year Treasury yield plus 580bps Authorized Revenue Requirement Increase(1) $45M Authorized ROE 9.75% Common Equity Ratio 49.48% Commission Approved Settlement 8/24/16 Cumulative Final Orders Authorized Revenue Requirement Increase(1) $317M BGE Final Order Authorized Revenue Requirement Increase(1,3) $92M Authorized ROE 9.75% (9.65% Gas) Common Equity Ratio 51.90% Order Received(3) 6/3/16

Exelon Utilities EPS Growth of 6-8% to 2020 $1.60 $1.50 Utility Adjusted Operating Earnings 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.

Exelon Generation: Gross Margin Update Gross margin categories rounded to nearest $50M Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on December 31, 2016, market conditions Reflects Oyster Creek retirement in December 2019 Variance to September 30, 2016 are on a pro-forma basis. See slide 44 for a full pro-forma of the September 30, 2016 gross margin in new format. Gross Margin disclosure now includes impacts of NY and IL ZECs, pending FitzPatrick acquisition, and reversal of the IL plant closures Behind ratable hedging position reflects the fundamental upside we see in power prices Generation ~6-9% open in 2017 Recent Developments Gross Margin Category ($M) (1) 2017 2018 2019 2017 2018 2019 Open Gross Margin (3) (including South, West, Canada hedged gross margin) $4,100 $4,200 $4,050 $300 $550 $450 Capacity and ZEC Revenues (3) $1,850 $2,250 $2,050 $400 $550 $600 Mark-to-Market of Hedges (3,4) $1,200 $450 $350 - $(50) $50 Power New Business / To Go $550 $900 $950 $(50) - - Non-Power Margins Executed $200 $100 $50 $50 - - Non-Power New Business / To Go $250 $400 $450 $(50) - - Total Gross Margin (2,5,6) $8,150 $8,300 $7,900 $650 $1,050 $1,100 December 31, 2016 Change from Sep 30, 2016 (7)

Adjusted O&M ($M)(1,2,3) Negative O&M CAGR reflects benefits of cost optimization program All amounts rounded to the nearest $25M O&M and Capital Expenditures reflect reversal of Quad Cities and Clinton retirement decisions and includes FitzPatrick Refer to slide 77 in the Appendix for a reconciliation of adjusted {non-GAAP) O&M to GAAP O&M Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments; incremental CapEx (Base and Fuel) impact from nuclear reversals and adding FitzPatrick for 2017, 2018, 2019, and 2020 at Q4 is $250M, $300M, $225M, and $275M, respectively Driving Cost and Capital Out of the Generation Business Capital Expenditures ($M)(1,4) All Other O&M

ExGen’s Strong Free Cash Flow Supports Utility Growth and Debt Reduction 2017-2020 Exelon Generation Free Cash Flow(1) and Uses of Cash ($B) Free Cash Flow is a non-GAAP Measure. See slide 77 for a reconciliation of free cash flow to the most comparable GAAP measures. Cumulative Free Cash Flow is a midpoint of a range based on December 31, 2016 market prices. 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) ~$6.8 (2)

Maintaining 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 A2 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. FFO/Debt is a non-GAAP measure. Please refer to slide 73 in the appendix for a reconciliation of FFO/Debt to the most comparable GAAP measure. Current senior unsecured ratings as of December 31, 2016 for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco Moody’s has ComEd on “Positive” outlook. All other 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. EBITDA, a non-GAAP measure, is defined as earnings before interest, taxes, depreciation and amortization. Includes nuclear fuel amortization expense. Please refer to slide 74 in the appendix for a reconciliation of Debt/EBITDA to the most comparable GAAP measure. ExGen Debt/EBITDA Ratio(5) Exelon S&P FFO/Debt %(1)(4) Credit Ratings by Operating Company 18%-20% x x 3.0x Excluding Non-Recourse Book S&P Threshold

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

Key Provisions of the Future Energy Jobs Bill Zero Emission Standard: Requires the Illinois Power Agency to procure contracts with zero emission facilities for zero emission credits (ZECs) equal to 16% of the actual electricity delivered in 2014. Cost of the program is capped at 1.65% of rates (about $235 million per year) for 10-year program duration and payments may be reduced by up to 10% if certain customer cost caps are exceeded. ZEC payment calculation (subject to the caps): Energy Efficiency: ComEd will increase spending to ~$400M at the peak of the program. This spending will be treated as traditional asset investment and ComEd will be able to earn a return on it. Formula Rate: Extends the ComEd Distribution formula rate until 2022 Decoupling: Revenue is decoupled from energy usage by eliminating the +/- 50 basis point collar in the formula rate Renewable Portfolio Standard: RPS is restructured to generate more renewable development, particularly, the law allows ComEd to propose developing a low-income community solar project and also will fund and place in rate base a solar rebate program for commercial and community solar developers Overall Cost Caps: Creates separate cost caps for residential, C&I, and large C&I customers that limit potential increases due to investment as a result of the legislation. Sets forth processes and remedies if projected or actual costs exceed the limitations specified in the legislation for the relevant customer class. (1) Social cost of carbon remains flat for first six years and then escalates at $1/MWH per year thereafter Social Cost of Carbon ($16.50/MWh) (1) Amount that market price index exceeds the baseline market price index of $31.40/MWh ZEC Payment

Exelon Utilities EPS Growth of 6-8% from 2017-2020 $1.41 $1.60 $1.50 Utility growth rate is still at 6-8% despite higher earnings in 2017 $1.40 Note: Analyst day reflects GAAP operating earnings. Q4 Earnings reflects GAAP operating earnings except for 2016A and 2017. For 2016A please refer to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS. 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 costs associated with utility investment. $1.75 Analyst Day $1.60 $1.50 $1.35 $1.70 Q4 Earnings $1.15 22

Utility Capex and Rate Base vs. Previous Disclosure Analyst Day Rate Base CapEx ($M) Over $20B of capital is being invested in utilities from 2017-2020 and rate base is growing at 6.5% from 2016-2020 Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. Q4 2016 CapEx ($M) Analyst Day Rate Base ($B) Q4 2016 Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding Other includes long-term regulatory assets, which earn a return consistent with rate base, including Energy Efficiency and the Solar Rebate Program Rate base reflects year-end estimates ComEd Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$7.7B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B)(2) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B) (1)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. PECO Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$3.1B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. BGE Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$3.7B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Note: Numbers rounded to nearest $25M and may not add due to rounding. Rate base reflects year-end estimates. PHI Consolidated Capital Expenditure and Rate Base Forecast Q4 2016 Capital Expenditures ($M) ~$5.5B of Capital being invested from 2017-2020 Q4 2016 Rate Base ($B) Analyst Day Capital Expenditures ($M) Analyst Day Rate Base ($B)

Pepco Holdings Capital Expenditures Note: Numbers rounded to nearest $25M and may not add due to rounding

Note: All numbers denote year-end rate base and may not add due to rounding. Rate base reflects year-end estimates. Pepco Holdings Rate Base Outlook Electric Distribution Electric Transmission Gas Delivery

1/17 2/17 3/17 ComEd Electric Distribution Formula Rate 4/17 Pepco Electric Distribution Rates - DC Delmarva Electric Distribution Rates - DE Delmarva Electric Distribution Rates - MD Exelon Utilities Distribution Rate Case Schedule 5/17 6/17 Note: Based on current schedules of Illinois Commerce Commission, Maryland Public Service Commission, DC Public Service Commission and Delaware Public Service Commission and are subject to change Delmarva Gas Distribution Rates - DE Rebuttal Testimony Jan 11 Evidentiary Hearings Mar 7-9 Rebuttal Testimony Due Feb 10 Evidentiary Hearings Apr 5-7 Commission Order Expected Feb 17 Rebuttal Testimony Feb 1 Evidentiary Hearings Mar 15-21 Final Reply Briefs Apr 24 2017 FRU Filing Mid-April 7/17 Commission Order Expected July 25 Rebuttal Testimory Mid-July

Adjusted O&M – Q3 2016 ($M)(1,2) Adjusted O&M - Q4 2016 ($M)(2) Capital and O&M now reflect reversal of IL plant closures and addition of FitzPatrick O&M and capital reflect the retirement of Clinton and Quad Cities and does not include cost of FitzPatrick acquisition Refer to slide 77 in the appendix for a reconciliation of adjusted {non-GAAP) O&M to GAAP O&M Capital spend represents cash CapEx with CENG at 100% and excludes merger commitments Incremental CapEx impact of nuclear reversals and adding FitzPatrick for 2017, 2018, 2019, and 2020 at Q4 is $250M, $300M, $225M, and $275M, respectively ExGen O&M and Capex vs. Previous Disclosure Capex - Analyst Day ($M)(1,3) Capex - Q4 2016 ($M)(3,4)

2016-2020 Exelon Generation Free Cash Flow and Uses of Cash Analyst Day(1) ($B) ($2.7 - $3.2) ($2.7 - $3.2) (~$2.3) (2) ~$8.2 Redeploying Exelon Generation’s free cash flow to maximize shareholder value Q4 2016(1) ($B) ($2.9 - $3.4) ($3.0 - $3.5) (~$2.3) (3) ~$8.7 Free Cash Flow is a non-GAAP Measure. See slide 77 for a reconciliation of free cash flow to the most comparable GAAP measures. Cumulative Free Cash Flow is a midpoint of a range based on June 30, 2016 market prices. It includes sources including change in margin, tax parent benefit, equity investments, and acquisitions and divestitures. Cumulative Free Cash Flow is a midpoint of a range based on December 31, 2016 market prices. It includes sources including change in margin, tax parent benefit, equity investments, and acquisitions and divestitures.

Theoretical Dividend Affordability from Utility less HoldCo(1,2) Utility less HoldCo payout ratio falling consistently even as dividend grows 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. 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 2019 and 2020; this does not signal a change in Board policy at this time. Quarterly dividends are subject to declaration by the board of directors. Midpoint of Payout Ratio Range Utility Earnings Payout Ratio (less HoldCo)

Adjusted O&M Forecast 2017 forecast of $8.5B(1) Expect CAGR of ~0.5% for 2016-2020 All amounts rounded to the nearest $25M Refer to the Appendix for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M. The Utilities adjusted O&M excludes regulatory O&M costs that are P&L neutral. ExGen adjusted O&M excludes direct cost of sales for certain Constellation businesses, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities. PHI Adjusted Operating O&M represents full year of spend (2) Key Year-over-Year Drivers(2) Nuclear Reversals + FitzPatrick: $225 Nuclear Outages: $75M PECO & BGE Storm Costs: $25M Utility Bad Debt Costs: $25M AMI Write-offs: ($75M) EIMA Program Ramp-Down: ($25M)

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 ExGen plans to issue $0.8B of long-term debt to fund dividend to parent to support LKE Operational excellence and financial discipline drives free cash flow reliability Generating $4.7B of free cash flow, including $1.6B at ExGen and $3.2B at the Utilities Creating value for customers, communities and shareholders Investing $6.1B, with $5.3B at the Utilities and $0.9B 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 Adjusted Cash Flow from Operations (non-GAAP) primarily includes net cash flows from operating activities and net cash flows from investing activities excluding capital expenditures, net M&A, and equity investments. Please refer to slide 76 for reconciliations to GAAP cash flow measures. 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 borrowing from Sumitomo, tax equity cash flows, capital leases, and CENG tax distributions to EDF ExGen Growth CapEx includes Phoenix, West Medway, AGE, Nuclear relicensing, Nuclear Uprates, and Retail Solar Dividends are subject to declaration by the Board of Directors. Includes cash flow activity from Holding Company, eliminations, and other corporate entities

Exelon Debt Maturity Profile Note: ExCorp debt includes $1,150M mandatory convertible units remarketing in 2017; ExGen debt includes legacy CEG debt; excludes securitized debt and non-recourse debt As of 12/31/16 ($M) Exelon’s weighted average LTD maturity is approximately 13 years

Discount rates changes of +/- 50 bps result in -/+ $65M - $85M change in pension and OPEB combined 2015 expense (EPS impact of ~$0.05) Pension and OPEB Contributions and Expense 2016(1) 2017 (in $M) Pre-Tax Expense(2) Contributions Pre-Tax Expense(2) Contributions Qualified Pension (3,4,5) $410 $310 $435 $310 Non-Qualified Pension 20 35 20 25 OPEB(4,5) 5 50 (5) 45 Total $435 $395 $450 $380 (1) PHI expense is included for the post-merger period (March 24 - December 31, 2016) (2) Pension and OPEB expenses assume a 30% and 27% capitalization rate for 2016 and 2017, respectively (3) The Balanced Funding Strategy for the Qualified Plans provides pension funding of the greater of $250M or minimum required contributions plus amounts required to avoid benefit restrictions and at-risk status for the legacy Exelon plans. PHI qualified plan contributions are $60M. (4) Expected return on assets for pension is 7.00% and for OPEB is 6.70% (5) Pension and OPEB discount rates are 4.29% for legacy Exelon plans and ~4% for PHI for 2016. Discount rates are 4.04% and ~4.11% for Exelon and PHI, respectively, for 2017.

Pension and OPEB – Funded Status and Performance Based on estimates from Goldman Sachs, the aggregate funded status for pension plans in S&P 500 companies is 82% at the end of 2016 Exelon is funded status for funding purposes (PPA) is significantly higher than PBO/GAAP funded status, which results in no required material pension contributions over the LRP period December 31, 2016 Funded Status Asset Investment Returns 7.3% 1.1 0.3 Discount Rate 4.05% from 4.29% 81% Funded 80% Funded Pension 2016 Funded Status (PBO) Comparison ($B) OPEB Funded Status December 31, 2016 ($B) 58% Funded

EPS Sensitivities Based on December 31, 2016 market conditions and hedged position. Gas price sensitivities are based on an assumed gas-power relationship derived from an internal model that is updated periodically. Power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant. Due to correlation of the various assumptions, the EPS impact calculated by aggregating individual sensitivities may not be equal to the EPS impact calculated when correlations between the various assumptions are also considered. Represents adjusted (non-GAAP) operating earnings. Refer to slide 72 for a list of adjustments from GAAP EPS to adjusted (non-GAAP) operating earnings. 2017 2018 2019 Henry Hub Natural Gas +$1/MMBtu $0.02 $0.16 $0.22 -$1/MMBtu $0.02 ($0.14) ($0.20) NiHub ATC Energy Price +$5/MWh $0.03 $0.16 $0.23 -$5/MWh ($0.03) ($0.16) ($0.23) PJM-W ATC Energy Price +$5/MWh $0.00 $0.05 $0.12 -$5/MWh $0.00 ($0.06) ($0.12) 30 Year Treasury Rate +50 basis points $0.02 $0.02 $0.03 -50 basis points ($0.02) ($0.02) ($0.03) Share Count (millions) 949 968 972 Effective Tax Rate ~34% ~34% ~33% ComEd EPS Impact ExGen EPS Impact (1,2) (2)

Historical Nuclear Capital Investment -0.5% Significant historical investments have mitigated asset management issues and prepared sites for license extensions already received, reducing future capital needs. In addition, internal cost initiatives have found more cost efficient solutions to large CapEx spend, such as levering reverse engineering replacements rather than large system wide modifications, resulting in baseline CAGR of -0.5%, even with net addition of 3 sites. (1) Reflects accrual capital expenditures with CENG at 50% ownership. Assumes Oyster Creek retirement by end of 2019. All numbers rounded to $25M. (2) Baseline includes ownership share of Salem all years. CENG is included at ownership share starting in 2014 (full year) (3) FitzPatrick included starting in 2017 (9 months only) (4) Growth represents capital that increases the capacity of the units (e.g., turbine upgrades, power uprates), and capital that extends the license of a site (e.g., License Renewals) (5) Includes CENG beginning in April 2014, excludes Salem and Fort Calhoun (6) 2016 industry average excluding Exelon was not available at time of publication (2,3,5) (4) Nuclear Baseline CAGR 2016(6) Nuclear Non-Fuel Capital Expenditures(1) ($M) Nuclear Capacity Factor(5) 40

Exelon Generation Disclosures December 31, 2016

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 Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on December 31, 2016 market conditions Reflects Oyster Creek retirement in December 2019

ExGen Disclosures Gross margin categories rounded to nearest $50M Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. Excludes EDF’s equity ownership share of the CENG Joint Venture Mark-to-Market of Hedges assumes mid-point of hedge percentages Based on December 31, 2016 market conditions Reflects Oyster Creek retirement in December 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 12 in 2019 at Exelon-operated nuclear plants and Salem.  Expected generation assumes capacity factors of  93.4%, 93.3% and 94.5% 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 Oyster Creek retirement in December 2019 Generation and Hedges 2017 2018 2019 Exp. Gen (GWh) (1) 204,800 208,300 211,700 Midwest 95,400 95,900 96,900 Mid-Atlantic (2,6) 60,200 60,300 60,000 ERCOT 23,000 28,100 29,100 New York (2) 14,500 15,400 16,600 New England 11,700 8,600 9,100 % of Expected Generation Hedged (3) 91%-94% 56%-59% 28%-31% Midwest 88%-91% 47%-50% 21%-24% Mid-Atlantic (2,6) 98%-101% 67%-70% 37%-40% ERCOT 85%-88% 60%-63% 32%-35% New York (2) 92%-95% 51%-54% 34%-37% New England 97%-100% 66%-69% 33%-36% Effective Realized Energy Price ($/MWh) (4) Midwest $32.00 $30.00 $29.50 Mid-Atlantic (2,6) $43.50 $38.50 $40.00 ERCOT (5) $6.50 $4.50 $3.50 New York (2) $42.00 $35.00 $31.50 New England (5) $15.00 $6.50 $6.50

ExGen Hedged Gross Margin Sensitivities Based on December 31, 2016 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 prices 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. Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Gross Margin Sensitivities (with Existing Hedges) (1) 2017 2018 2019 Henry Hub Natural Gas ($/Mmbtu) + $1/Mmbtu $35 $250 $345 - $1/Mmbtu $25 $(225) $(310) NiHub ATC Energy Price + $5/MWh $45 $250 $360 - $5/MWh $(45) $(245) $(360) PJM-W ATC Energy Price + $5/MWh $5 $85 $195 - $5/MWh $5 $(90) $(185) NYPP Zone A ATC Energy Price + $5/MWh $5 $40 $50 - $5/MWh $(10) $(35) $(50) Nuclear Capacity Factor +/- 1% +/- $40 +/- $40 +/- $35

ExGen Hedged Gross Margin Upside/Risk Approximate Gross Margin ($ million)(1,2,3,4) $8,500 $7,850 $9,250 $7,500 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 December 31, 2016. Gross Margin Upside/Risk based on commodity exposure which includes open generation and all committed transactions Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. Excludes EDF’s equity ownership share of the CENG Joint Venture. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure. Reflects Oyster Creek retirement in December 2019 $6,700 $9,500

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) 95.9 60.3 28.1 15.4 8.6 (D) Hedge % (assuming mid-point of range) 48.5% 68.5% 61.5% 52.5% 67.5% (E=C*D) Hedged Volume (TWh) 46.5 41.3 17.3 8.1 5.8 (F) Effective Realized Energy Price ($/MWh) $30.00 $38.50 $4.50 $35.00 $6.50 (G) Reference Price ($/MWh) $27.76 $32.02 $2.48 $30.63 $5.93 (H=F-G) Difference ($/MWh) $2.24 $6.48 $2.02 $4.37 $0.57 (I=E*H) Mark-to-Market value of hedges ($ million) (1) $105 $270 $35 $35 $5 (J=A+B+I) Hedged Gross Margin ($ 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 (2) $100 $400 $8,300 million $4.2 billion $6,900 $900 $2.25 billion Illustrative Example of Modeling Exelon Generation 2018 Gross Margin Mark-to-market rounded to the nearest $5 million Total Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. Refer to slide 50 for a reconciliation of Total Gross Margin to the most comparable GAAP measure.

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2017 2018 2019 Revenue Net of Purchased Power and Fuel Expense(2,3) $8,850 $8,975 $8,575 Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at merger date $50 - - Other Revenues(4) $(350) $(275) $(275) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) $(400) $(400) $(400) Total Gross Margin (Non-GAAP) $8,150 $8,300 $7,900 All amounts rounded to the nearest $25M Revenue net of purchased power and fuel expense (RNF), a non-GAAP measure, is calculated as the GAAP measure of operating revenue less the GAAP measure of purchased power and fuel expense. 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 operating services agreement with Fort Calhoun, 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 businesses of Generation ExGen amounts for O&M, TOTI, Depreciation & Amortization; excludes EDF’s equity ownership share of the CENG Joint Venture ExGen adjusted O&M excludes direct cost of sales for certain Constellation business, P&L neutral decommissioning costs and the impact from O&M related to variable interest entities. Refer to slide 75 for a reconciliation of adjusted (non-GAAP) O&M to GAAP O&M. TOTI excludes gross receipts tax of $100M Interest expense includes impact of reduced capitalized interest due to Texas CCGT plants going into service in 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 Revenues (excluding Gross Receipts Tax)(4) $200 Adjusted O&M(7) $(4,850) Taxes Other Than Income (TOTI)(8) $(375) Depreciation & Amortization $(1,150) Interest Expense(9) $(425) Effective Tax Rate 32.0%

2016A Earnings Waterfalls

FY Adjusted Operating Earnings Waterfall (1,2) $0.06 Distribution & Transmission Investment $0.03 Weather ($0.01) ROE (US Treasuries) $0.08 Increased rates ($0.01) O&M (Vegetation/Other) ($0.01) Weather ($0.01) D&A $0.05 Increased Distribution and Transmission rates ($0.04) Rate case disallowances ($0.01) Storms Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Amounts may not add due to rounding ($0.08) D&A ($0.05) Share differential ($0.04) Taxes, primarily DPAD & IL Apportionment ($0.02) NDT fund gains $0.05 Nuclear outages $0.02 Pension & Fringe Benefits ($0.01) Other

Q4 Adjusted Operating Earnings Waterfall (1,2) $0.05 Nuclear outages (inc. Salem) ($0.01) Lower Realized Energy Pricing ($0.01) D&A ($0.01) NDT fund gains $0.02 Weather $0.01 Increase Rates ($0.01) Bad debt expense ($0.01) Other $0.02 Baltimore City Conduit fee settlement $0.01 Increased Distribution rates Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Amounts may not add due to rounding

2017E Earnings Waterfalls

$0.60 - $0.70 (1) (4,5) (3) (2) ComEd Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. (5) Guidance assumes an effective tax rate for 2017 of 39.9% $0.08 Distribution $0.03 Transmission $0.04 Energy Efficiency $0.02 ROE (US Treasury yields) ($0.01) Weather/Load ($0.05) Depreciation & Amortization ($0.03) Energy Efficiency Amortization

(1) (2) (4,5) $0.40 - $0.50 (3) PECO Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS (5) Guidance assumes an effective tax rate for 2017 of 21.8% ($0.01) Inflation ($0.01) Storm

2017(4,5) (3) (2) 2016(1) $0.25 - $0.35 BGE Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (3) O&M excludes regulatory items that are P&L neutral (4) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS (5) Guidance assumes an effective tax rate for 2017 of 39.5% $0.03 Pricing/Mix $0.01 Transmission $0.04 Rate Case disallowances ($0.01) Storm Costs ($0.01) Bad Debt ($0.01) Baltimore City Conduit Fee ($0.01) Other ($0.03) D&A ($0.01) TOTI ($0.01) Other

2017(5,6) (4) ($0.01) (3) (2) 2016(1) $0.30 - $0.40 PHI Adjusted Operating EPS Bridge 2016 to 2017 ($0.02) D&A ($0.03) Other $0.08 Distribution $0.03 Transmission Note: Drivers add up to mid-point of 2017 adjusted operating EPS range (1) Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS (2) Stub period earnings reflect earnings prior to merger close date of March 23, 2016 (3) Revenue net fuel (RNF) is defined as operating revenues less purchased power and fuel expense (4) O&M excludes regulatory items that are P&L neutral (5) Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. (6) Guidance assumes an effective tax rate for 2017 of 35.6%

(5,6) (4) (3) (2) (1) $1.05 - $1.15 ExGen Adjusted Operating EPS Bridge 2016 to 2017 Note: Drivers add up to mid-point of 2017 adjusted operating EPS range. Refer to the Earnings Release Attachments for additional details and to the Appendix for a reconciliation of adjusted (non-GAAP) operating EPS to GAAP EPS Gross Margin (Non-GAAP) is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, Exelon Nuclear Partners, operating services agreement with Fort Calhoun and variable interest entities. Total Gross Margin is also net of direct cost of sales for certain Constellation and Power businesses. See Slide 50 for a Non-GAAP to GAAP reconciliation of Total Gross Margin. O&M excludes items that are P&L neutral (including decommissioning costs and variable interest entities) and direct cost of sales for certain Constellation businesses Depreciation & Amortization excludes cost of sales for certain Constellation businesses, which are included in gross margin Shares Outstanding (diluted) are 927M in 2016 and 949M in 2017. Refer to slide 72 for a reconciliation of adjusted (non-GAAP) operating EPS guidance to GAAP EPS. Guidance assumes an effective tax rate for 2017 of 32% $0.32 NY + IL Legislation, including FitzPatrick $0.16 Capacity + New Builds ($0.29) Unfavorable Market Conditions ($0.03) Other ($0.02) FitzPatrick + Clinton + Quad Cities ($0.03) Power Growth Projects ($0.02) Other ($0.13) FitzPatrick + Clinton + Quad Cities ($0.07) Outages $0.03 Other ($0.05) Interest ($0.03) Share Dilution ($0.01) Other

Exelon Utilities Rate Case Filing Summaries

ComEd April 2016 Distribution Formula Rate Docket # 16-0259 Filing Year 2015 Calendar Year Actual Costs and 2016 Projected Net Plant Additions are used to set the rates for calendar year 2017. Rates currently in effect (docket 15-0287) for calendar year 2016 were based on 2014 actual costs and 2015 projected net plant additions. Reconciliation Year Reconciles Revenue Requirement reflected in rates during 2015 to 2015 Actual Costs Incurred. Revenue requirement for 2015 is based on docket 14-0312 (2013 actual costs and 2014 projected net plant additions) approved in December 2014. Common Equity Ratio ~46% for both the filing and reconciliation year ROE 8.64% for the filing year (2015 30-yr Treasury Yield of 2.84% + 580 basis point risk premium) and 8.59% for the reconciliation year (2015 30-yr Treasury Yield of 2.79% + 580 basis point risk premium – 5 basis points performance metrics penalty). For 2016 and 2017, 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 ~7% for both the filing and reconciliation years Rate Base(1) $8,831 million– Filing year (represents projected year-end rate base using 2015 actual plus 2016 projected capital additions). 2016 and 2017 earnings will reflect 2016 and 2017 year-end rate base respectively. $7,782 million - Reconciliation year (represents year-end rate base for 2015) Revenue Requirement Increase(1) $127M increase ($7M decrease due to the 2015 reconciliation and collar adjustment offset by a $134M increase related to the filing year). The 2015 reconciliation impact on net income was recorded in 2015 as a regulatory asset. Timeline 04/13/16 Filing Date 240 Day Proceeding The 2016 distribution formula rate filing established the net revenue requirement used to set the rates that took effect in January 2017 after the Illinois Commerce Commission's (ICC’s) review. There are two components to the annual distribution formula rate filing: Filing Year: Based on 2015 costs and 2016 projected plant additions. Annual Reconciliation: For 2015, this amount reconciles the revenue requirement reflected in rates in effect during 2015 to the actual costs for that year. The annual reconciliation impacts cash flow in 2017 but the earnings impact has been recorded in 2015 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. Amounts represent the approved amounts within the Illinois Commerce Commission’s final order, received on December 6, 2016. The ICC ordered rehearing on one narrow topic that ComEd expects to result in a further $17.5M reduction to the revenue requirement.

Pepco MD Electric Distribution Rate Case – Final Order Docket # 9418 Test Year 2015 Calendar Year Test Period 12 months actual Authorized Common Equity Ratio 49.55% Authorized Rate of Return ROE: 9.55%; ROR: 7.49% Authorized Rate Base Rate Base: $1.64B Authorized Revenue Requirement Increase Revenue Increase: $52.5M Revenue increase includes approximately $32.1M of new depreciation and amortization expense. Residential Total Bill % Increase 4.76% Notes Order received on November 15 Advanced Metering (AMI) system deemed cost-beneficial and recovery to begin Post-test period AMI costs deferred to new regulatory asset Legacy meter recovery approved over 10 years with no return Post-test period reliability capital placed in service through March 2016 approved with some disallowance Extension of the Grid Resiliency Program in 2017-2018 was not approved

DPL DE (Electric) Distribution Rate Case Docket # 16-0649 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.44% Requested Rate of Return ROE: 10.60%; ROR: 7.19% Proposed Rate Base (Adjusted) $839M Requested Revenue Requirement Increase (Updated on January 11, 2017) $60.2M(1)(2) Residential Total Bill % Increase 7.25% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in electric distribution base rates Intervenor Positions: Staff $9.5M revenue increase based on 9.20% ROE Division of the Public Advocate (DPA) $12.9M revenue increase based on 9.00% ROE Procedural Schedule: Evidentiary Hearings: 3/7/17 – 3/9/17 Commission Order Expected: Q3 2017 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

DPL DE (Gas) Distribution Rate Case Docket # 16-0650 Test Year 2015 Calendar Year Test Period 12 months actual Requested Common Equity Ratio 49.44% Requested Rate of Return ROE: 10.60%; ROR: 7.19% Proposed Rate Base (Adjusted) $362M Requested Revenue Requirement Increase $21.5M(1)(2) Residential Total Bill % Increase 10.40% Notes 5/17/16 DPL DE filed application with the DPSC seeking increase in gas distribution base rates Intervenor Positions: Staff revenue decrease of $3.1M based on 9.20% ROE Division of the Public Advocate (DPA) revenue decrease of $2.1M based on 9.00% ROE Procedural Schedule: Evidentiary Hearings: 4/5/17 – 4/7/17 Commission Order Expected: Q3 2017 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

Pepco DC Distribution Rate Case Formal Case No. 1139 Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.14% Requested Rate of Return ROE: 10.60%; ROR: 8.00% Proposed Rate Base (Adjusted) $1.7B Requested Revenue Requirement Increase (Updated on February 1, 2017) $76.8M(1) Residential Total Bill % Increase 4.62%(2) Notes 6/30/16 Pepco DC filed application with the DCPSC seeking increase in electric distribution base rates Intervenor Positions: Office of the People’s Council (OPC) revenue increase of $20.1M 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 Procedural Schedule: Evidentiary Hearings: 3/15/17 – 3/21/17 Final Briefs: 4/24/17 Commission Order Expected: 7/25/17 Revenue requirement includes changes in amortization expense, which has no impact on pre-tax earnings As proposed by the Company, the full allocation of the CBRC to Residential and MMA customers, along with the proposal for a $1M Incremental Offset for residential customers, will ensure that residential customers do not receive an increase on the distribution portion of their bill until approximately January 2019 (February 2019 for MMA customers). Upon expiration of the CBRC and Incremental Offset proposed by the Company, this rate increase would translate to a 4.62% total bill increase for a residential customer.

DPL MD Distribution Rate Case Case No. 9424 Company’s Filed Position Chief Public Utility Law Judge (CPULJ) Test Year April 1, 2015 – March 31, 2016 Test Period 12 months actual Requested Common Equity Ratio 49.1% 49.1% Requested Rate of Return ROE: 10.60%; ROR: 7.24% ROE: 9.48%; ROR: 6.69% Proposed Rate Base (Adjusted) $727M $706M Requested Revenue Requirement Increase (Updated on October 18, 2016) $57M $34.1M Residential Total Bill % Increase 14.5% 6.53% Notes 7/20/16 DPL MD filed application with the MDPSC seeking increase in electric distribution base rates Intervenor Positions: Staff revenue increase of $37.4M based on 9.48% ROE Office of the People’s Council (OPC) revenue increase of $22.9M based on 8.60% ROE Intervenors: Staff, OPC, Maryland Energy Group and Hanover Foods Procedural Schedule: CPULJ Proposed Order Received: 1/4/17 Commission Order Expected: 2/17/17 1/4/17 the CPULJ issued a proposed order Advanced Metering (“AMI”) system deemed cost-beneficial, and recovery to begin Legacy meter recovery approved over 10 years, with no return Post-test period reliability capital placed in service through September 2016 approved Extension of the Grid Resiliency Program in 2017-2018 was not approved The Company filed an appeal on January 18

Appendix Reconciliation of Non-GAAP Measures

4Q QTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Three Months Ended December 31, 2015 ExGen ComEd PECO BGE PHI Other Exelon 2015 GAAP Earnings (Loss) Per Share $0.17 $0.09 $0.09 $0.08 $0.00 $(0.09) $0.33 Unrealized gains related to NDT fund investments (0.05) - - - - - (0.05) Merger and integration costs - - - - - 0.01 0.01 Amortization of commodity contract intangibles 0.01 - - - - - 0.01 Long-Lived asset impairments 0.01 - - - - - 0.01 Reassessment of state deferred income taxes 0.01 - - - - 0.03 0.05 Reduction in state income tax reserve (0.01) - - - - - (0.01) PHI merger related redeemable debt exchange - - - - - 0.01 0.01 CENG non-controlling interest 0.02 - - - - - 0.02 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.15 $0.09 $0.09 $0.08 $0.00 $(0.04) $0.38

4Q QTD GAAP EPS Reconciliation (continued) Three Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP (Loss) Earnings Per Share $(0.04) $0.09 $0.10 $0.11 $0.03 $(0.06) $0.22 Mark-to-Market impact of economic hedging activities (0.05) - - - - - (0.05) Unrealized losses related to NDT fund investments 0.01 - - - - - 0.01 Amortization of commodity contract intangibles 0.03 - - - - - 0.03 Merger and integration costs 0.02 - - - - - 0.02 Reassessment of state deferred income taxes 0.02 - - - - - 0.01 Asset retirement obligation (0.08) - - - - - (0.08) Merger commitments 0.04 - - - 0.01 (0.01) 0.04 Plant retirements and divestitures 0.10 - - - - - 0.10 Cost management program 0.01 - - - - - 0.01 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 CENG non-controlling interest 0.07 - - - - - 0.07 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.18 $0.09 $0.10 $0.11 $0.05 $(0.08) $0.44 NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding.

4Q YTD GAAP EPS Reconciliation NOTE: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not add due to rounding. Twelve Months Ended December 31, 2015 ExGen ComEd PECO BGE PHI Other Exelon 2015 GAAP Earnings (Loss) Per Share $1.54 $0.48 $0.42 $0.31 $0.00 $(0.20) $2.54 Mark-to-Market impact of economic hedging activities (0.18) - - - - - (0.18) Unrealized losses related to NDT fund investments 0.13 - - - - - 0.13 Merger and integration costs 0.02 0.01 - - - 0.03 0.07 Mark-to-market impact of PHI merger related interest rate swap - - - - - 0.02 0.02 Long-lived asset impairments 0.01 - - - - 0.02 0.02 Asset retirement obligation (0.01) - - - - - (0.01) Tax settlements (0.06) - - - - - (0.06) Midwest generation bankruptcy recoveries (0.01) - - - - - (0.01) PHI merger related redeemable debt exchange - - - - - 0.01 0.01 Reassessment of state deferred income taxes 0.01 - - - - 0.03 0.05 Reduction in state income tax reserve (0.01) - - - - - (0.01) CENG non-controlling interest (0.04) - - - - - (0.04) 2015 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.40 $0.48 $0.43 $0.31 $0.00 $(0.13) $2.49

4Q YTD GAAP EPS Reconciliation (continued) Twelve Months Ended December 31, 2016 ExGen ComEd PECO BGE PHI Other Exelon 2016 GAAP Earnings (Loss) Per Share $0.54 $0.41 $0.47 $0.31 ($0.07) ($0.44) $1.22 Mark-to-Market impact of economic hedging activities 0.03 - - - - - 0.03 Unrealized gains related to NDT fund investments (0.13) - - - - - (0.13) Amortization of commodity contract intangibles 0.04 - - - - - 0.04 Merger and integration costs 0.04 - - - 0.05 0.04 0.12 Long-lived asset impairments 0.11 - - - - - 0.11 Asset retirement obligation (0.08) - - - - - (0.08) Reassessment of state deferred income taxes 0.02 - - - - (0.01) 0.01 Merger commitments 0.05 - - - 0.27 0.16 0.47 Plant retirements and divestitures 0.47 - - - - - 0.47 Cost management program 0.03 - - - - - 0.04 Like-kind exchange tax position - 0.16 - - - 0.05 0.21 Curtailment of Generation growth and development activities 0.06 - - - - - 0.06 CENG non-controlling interest 0.11 - - - - - 0.11 2016 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $1.27 $0.57 $0.48 $0.31 $0.25 ($0.20) $2.68 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 and losses from NDT fund investments to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements Non-cash amortization of intangible assets, net, related to commodity contracts recorded at fair value at the date of acquisition of Integrys in 2014 and ConEdison Solutions in 2016 Certain costs incurred associated with the PHI acquisition and pending FitzPatrick acquisition Costs incurred related to a cost management program Generation’s non-controlling interest related to CENG exclusion items Other unusual items

All amounts rounded to the nearest $25M Calculated using S&P Methodology. Due to ring-fencing, S&P deconsolidates BGE from Exelon and analyzes solely as an equity investment. Reflects impact of operating adjustments on GAAP EBITDA. Refer to slide 72 for a list of operating adjustments to GAAP. Includes other adjustments as prescribed by S&P Reflects present value of net capacity purchases Reflects present value of minimum future operating lease payments Reflects after-tax unfunded pension/OPEB Includes non-recourse project debt and mandatory convertible equity units Applies 75% of excess cash against balance of LTD YE 2017 Exelon FFO Calculation ($M)(1) GAAP Operating Income $4,400 Depreciation & Amortization $2,875 EBITDA $7,275 +/- Non-operating activities and nonrecurring items(3) $375 - Interest Expense ($1,425) + Current Income Tax (Expense)/Benefit ($125) + Nuclear Fuel Amortization $1,050 +/- Other S&P FFO Adjustments(4) $425 = FFO (a) $7,575 YE 2017 Exelon Adjusted Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $32,700 Short-Term Debt $1,875 + PPA Imputed Debt(5) $350 + Operating Lease Imputed Debt(6) $850 + Pension/OPEB Imputed Debt(7) $3,450 - Off-Credit Treatment of Debt(8) ($2,225) - Surplus Cash Adjustment(9) ($550) +/- Other S&P FFO Adjustments(4) $300 = Adjusted Debt (b) $36,750 YE 2017 Exelon FFO/Debt(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) $9,525 Short-Term Debt $825 - Surplus Cash Adjustment ($375) = Net Debt (a) $9,975 YE 2017 Book Debt / EBITDA Net Debt (a) = 3.3x Operating EBITDA (b) All amounts rounded to the nearest $25M Reflects impact operating adjustments on GAAP EBITDA. Refer to slide 72 for a list of operating adjustments to GAAP. YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,225 Depreciation & Amortization $1,200 EBITDA $2,425 +/- Non-operating activities and nonrecurring items(2) $600 = Operating EBITDA (b) $3,025 GAAP to Non-GAAP Reconciliations YE 2017 ExGen Net Debt Calculation ($M)(1) Long-Term Debt (including current maturities) $9,525 Short-Term Debt $825 - Surplus Cash Adjustment ($375) - Nonrecourse Debt ($2,550) = Net Debt (a) $7,425 YE 2017 Recourse Debt / EBITDA Net Debt (a) = 2.7x Operating EBITDA (b) YE 2017 ExGen Operating EBITDA Calculation ($M)(1) GAAP Operating Income $1,225 Depreciation & Amortization $1,200 EBITDA $2,425 +/- Non-operating activities and nonrecurring items(2) $600 - EBITDA from projects financed by nonrecourse debt ($250) = Operating EBITDA (b) $2,775

2016 Adjusted O&M Reconciliation ($M)(1) ExGen ComEd PECO BGE PHI(4) Other Exelon GAAP O&M $5,650 $1,525 $800 $725 $1,525 $100 $10,325 Regulatory O&M(2) - (225) (75) - (100) - (400) Long-lived asset impairment costs (175) - - - - - (175) Merger commitments and costs to achieve - - - - (475) (200) (675) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (475) -  - - - - (475) O&M for managed plants that are partially owned (400) - - - - - (400) Other (25) - - - 25 - - Adjusted O&M (Non-GAAP) $4,575 $1,300 $725 $725 $975 $(100) $8,200 All amounts rounded to the nearest $25M Reflects earnings neutral O&M Reflects the direct cost of sales of certain Constellation and Power businesses of Generation, which are included in Total Gross Margin All amounts represent full year of spend at PHI GAAP to Non-GAAP Reconciliations 2017 Adjusted O&M Reconciliation ($M)(1) ExGen ComEd PECO BGE PHI Other Exelon GAAP O&M $5,775 $1,300 $850 $750 $1,100 ($125) $9,650 Regulatory O&M(2) - (25) (75) ($25) (100) - (225) Decommissioning(2) 25 - - - - - 25 Long-lived asset impairment costs - - - - - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (400) -  - - - - (400) O&M for managed plants that are partially owned (425) - - - - - (425) Other (125) - - - (25) - (150) Adjusted O&M (Non-GAAP) $4,850 $1,275 $775 $725 $975 $(125) $8,475

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) $950 $725 $700 $1,125 $3,475 ($300) $6,650 Other cash from investing activities - - $25 - ($275) - ($250) Intercompany receivable adjustment ($350) - - - - $350 - Counterparty collateral activity - - - - $425 - $425 Adjusted Cash Flow from Operations $600 $725 $725 $1,125 $3,625 $50 $6,825 2017 Cash From Financing Calculation ($M)(1) ComEd PECO BGE PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $1,200 $175 $200 $125 ($200) $425 $1,950 Dividends paid on common stock $425 $300 $200 $250 $650 ($575) $1,225 Intercompany receivable adjustment $350 - - - - ($350) - Financing Cash Flow $1,975 $475 $400 $375 $475 ($500) $3,175 Exelon Total Cash Flow Reconciliation(1) 2017 GAAP Beginning Cash Balance $650 Adjustment for Cash Collateral Posted $375 Adjusted Beginning Cash Balance(3) $1,025 Net Change in Cash (GAAP)(2) $550 Adjusted Ending Cash Balance(3) $1,575 Adjustment for Cash Collateral Posted ($800) 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 76

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2017 2018 2019 2020 GAAP O&M $5,775 $5,525 $5,500 $5,575 Decommissioning(2) 25 50 50 50 Costs associated with early nuclear plant retirements - - - - Long-lived asset impairment costs - - - - Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(3) (400) (400) (400) (400) O&M for managed plants that are partially owned (425) (425) (425) (450) Other (125) - - - Adjusted O&M (Non-GAAP) $4,850 $4,725 $4,725 $4,775 All amounts rounded to the nearest $25M Reflects earnings neutral O&M Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin, a non-GAAP measure Baseline capital expenditures refer to maintenance and required capital expenditures necessary for day-to-day plant operations and includes merger commitments 2016-2020 ExGen FCF Calculation – Analyst Day ($M)(1) Cash from Operations (GAAP) $17,975 Other Cash from Investing Activities ($600) Baseline Capital Expenditures(4) ($4,625) Nuclear Fuel Capital Expenditures ($4,525) Free Cash Flow before Growth CapEx and Dividend $8,225 2016-2020 ExGen FCF Calculation - Q4 2016 ($M)(1) Cash from Operations (GAAP) $19,150 Other Cash from Investing Activities ($600) Baseline Capital Expenditures(4) ($4,950) Nuclear Fuel Capital Expenditures ($4,850) Free Cash Flow before Growth CapEx and Dividend $8,750 2017-2020 ExGen Free Cash Flow Calculation ($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

GAAP to Non-GAAP Reconciliations ACE, Delmarva, and Pepco represents full year of earnings Operating ROE Reconciliation(1) ACE Delmarva Pepco Legacy EXC Consolidated EU Net Income (GAAP)(1) ($42) ($9) $50 $1,102 $1,103 Operating exclusions $99 $89 $127 $146 $461 Adjusted Operating Earnings(1) $57 $80 $177 $1,258 $1,564 Average Equity $1,020 $1,280 $2,272 $11,951 $16,523 Operating ROE (Adjusted Operating Earnings/Average Equity) 5.6% 6.3% 7.5% 10.5% 9.5%