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Peco Energy

Filed: 3 Nov 20, 6:53am
Earnings Conference Call Third Quarter 2020 November 3, 2020


 

Cautionary Statements Regarding Forward-Looking Information This presentation contains certain written and oral forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including among others those related to the expected or potential impact of the novel coronavirus (COVID-19) pandemic, and the related responses of various governments and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are intended to identify such forward- looking statements. 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) the Registrants’ 2019 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18, Commitments and Contingencies; (2) the Registrants’ Third Quarter 2020 Quarterly Report on Form 10-Q (to be filed on November 3, 2020) in (a) Part II, ITEM 1A. Risk Factors; (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations and (c) Part I, ITEM 1. Financial Statements: Note 14, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants. Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, 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. 2 Q3 2020 Earnings Release Slides


 

Non-GAAP Financial Measures Exelon reports its financial results in accordance with accounting principles generally accepted in the United States (GAAP). Exelon supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted operating earnings exclude certain costs, expenses, gains and losses and other specified items, including mark-to- market adjustments from economic hedging activities, unrealized gains and losses from nuclear decommissioning trust fund investments, asset impairments, certain amounts associated with plant retirements and divestitures, costs related to cost management programs, asset retirement obligations and other items as set forth in the reconciliation in the Appendix • Adjusted operating and maintenance expense excludes regulatory operating and maintenance costs for the utility businesses and direct cost of sales for certain Constellation and Power businesses, decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Generation, EDF’s ownership of O&M expenses, and other items as set forth in the reconciliation in the Appendix • Total gross margin is defined as operating revenues less purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, 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 3 Q3 2020 Earnings Release Slides


 

Non-GAAP Financial Measures Continued This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Exelon’s baseline operating performance by excluding items that are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. These non-GAAP financial measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations. 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 36 of this presentation. 4 Q3 2020 Earnings Release Slides


 

Third Quarter Results Q3 2020 EPS Results(1) Q3 2020 Highlights/Key Developments $1.04 • Active summer storm season, including Tropical Storm Isaias $0.47 • Named 30 suppliers and professional services firms to Exelon $0.51 ExGen $0.05 Diversity and Inclusion Honor Roll BGE $0.05 $0.06 • Selected 10 startups as part of $0.14 PECO $0.14 Climate Change Investment Initiative PHI $0.22 $0.23 • Announced retirements of Dresden and Byron nuclear stations and Mystic Generating station ComEd $0.20 $0.20 ($0.05) HoldCo ($0.16) Q3 GAAP Earnings Q3 Adjusted Operating Earnings* (1) Amounts may not sum due to rounding 5 Q3 2020 Earnings Release Slides


 

Operating Highlights Exelon Utilities Operational Metrics Exelon Generation Operational Performance YTD 2020 (2) Operations Metric Exelon Nuclear Fleet BGE ComEd PECO PHI • Best in class performance across our Nuclear fleet: OSHA Recordable Rate ― Q3 2020 Nuclear Capacity Factor: 96.0% Electric 2.5 Beta SAIFI ― Owned and operated Q3 2020 production of Operations (Outage Frequency)(1) 37.9 TWh 2.5 Beta CAIDI (Outage Duration) 44 100% 98% Customer 42 Customer Satisfaction 96% Operations 40 94% Capacity Factor Abandon Rate 92% 38 90% Gas No Gas TWhrs 36 Gas Odor Response 88% Operations Operations 34 86% 84% • Despite storms that interrupted service in our jurisdictions, 32 82% reliability performance was strong across the utilities: 30 80% ― ComEd delivered top decile CAIDI and SAIFI performance Q3 18 Q4 18 Q1 19 Q2 19 Q3 19 Q4 19 Q1 20 Q2 20 Q3 20 • Each utility continued to deliver on key customer operations TWhrs Capacity Factor metrics: ― BGE, ComEd and PECO recorded top decile performance in Fossil and Renewable Fleet Customer Satisfaction ― PHI achieved top decile performance in Abandon Rate • Q3 2020 Power Dispatch Match: 98.9% • BGE and PECO performed in top decile in Gas Odor Response • Q3 2020 Renewables Energy Capture: 91.9% Quartile Q1 Q2 Q3 Q4 (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture 6 Q3 2020 Earnings Release Slides


 

Third Quarter Adjusted Operating Earnings* Drivers Q3 2020 Adjusted Operating EPS* Results Q3 2020 vs. Guidance of $0.80 - $0.90 $1.04 • Adjusted (non-GAAP) operating earnings drivers versus guidance: ExGen $0.47 Exelon Utilities – Favorable O&M and taxes BGE $0.06 – Earlier recognition of bad debt regulatory asset PECO $0.14 – Favorable weather – Storm costs PHI $0.23 $0.57 Exelon Generation – Favorable O&M ComEd $0.20 – Favorable weather HoldCo ($0.05) – Lower cost to serve Q3 2020 Note: Amounts may not sum due to rounding 7 Q3 2020 Earnings Release Slides


 

Q3 2020 QTD Adjusted Operating Earnings* Waterfall $0.02 Distribution and Transmission Rate Increases ($0.01) Storm Costs(1) $0.01 Other $0.01 Favorable Weather $0.01 Other ($0.01) Storm Costs(1) $1.04 $0.01 $0.92 $0.11 ($0.01) $0.00 $0.00 $0.02 $0.05 Lower Operating and Maintenance Expense(2) ($0.01) Other $0.03 Capacity Revenues ($0.01) Market and Portfolio Conditions $0.04 Other(3) $0.01 Distribution Rate Increase ($0.01) Other 2019 ComEd PECO BGE PHI ExGen(4) Corp 2020 Note: Amounts may not sum due to rounding (1) Primarily reflects increased costs attributable to the August 2020 storm. At PECO, amount is net of tax repairs. (2) Primarily reflects lower contracting and travel costs (3) Includes the impacts of lower nuclear fuel costs (4) Drivers reflect CENG ownership at 100% 8 Q3 2020 Earnings Release Slides


 

Raising 2020 Adjusted Operating Earnings* Guidance $3.00 - $3.20(2) $2.80 - $3.10(1) $1.25 - $1.35 ExGen $1.10 - $1.20 BGE $0.30 - $0.40 $0.30 - $0.40 PECO $0.40 - $0.50 $0.40 - $0.50 PHI $0.50 - $0.60 $0.50 - $0.60 ComEd $0.60 - $0.70 $0.60 - $0.70 HoldCo ($0.20) ($0.20) 2020 Q1 Revised Guidance 2020 Q3 Revised Guidance Note: Amounts may not sum due to rounding (1) 2020E Q1 revised earnings guidance based on expected average outstanding shares of 976M (2) 2020E Q3 revised earnings guidance based on expected average outstanding shares of 977M 9 Q3 2020 Earnings Release Slides


 

Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 10.2% 10.2% 10.1% 10.0% 9.6% 9.6% 9.7% 9.4% 9.3% 9.4% 9.1% 8.9% Q4 2017 Q1 2018 Q2 2018 Q3 2018 Q4 2018 Q1 2019 Q2 2019 Q3 2019 Q4 2019 Q1 2020 Q2 2020 Q3 2020 Exelon Utilities’ Consolidated TTM Earned ROE* has dipped slightly below our 9-10% target range due to pressures from declining interest rates, storms and unfavorable Q1 weather Note: Represents the twelve-month periods ending September 30, 2018-2020, June 30, 2018-2020, March 31, 2018-2020 and December 31, 2017-2019. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Q3 2019, Q2 2019, Q1 2019, Q4 2018, Q3 2018, Q2 2018, Q1 2018 and Q4 2017 TTM ROEs* for Consolidated EU were changed from 10.1%, 10.2%, 10.2%, 9.7%, 9.6%, 9.4%, 9.4% and 9.5%, respectively, to 10.1%, 10.2%, 10.2%, 9.6%, 9.6%, 9.4%, 9.3% and 9.4%, respectively, to reflect the correction of an error at PHI. 10 Q3 2020 Earnings Release Slides


 

Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Requested Revenue Expected Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun ROE / Requirement Order Equity Ratio (1,2) 8.38% / ComEd RT EH IB RB FO ($13.6M) Dec 2020 48.16% (1,3) $228.1M 10.10% / BGE IT RT EH IB RB FO Dec 2020 3-Year MYP 52.00% (1,4) $135.9M 9.70% / Pepco DC EH IB RB FO Q1 2021 3-Year MYP 50.68% DPL DE (1,5) 10.30% / IT RT EH IB RB FO $7.2M Q1 2021 Gas 50.37% DPL DE (1,6) 10.30% / IT RT EH FO $24.0M Q2 2021 Electric 50.37% (1,7) $110.1M 10.20% / May 2021 Pepco MD CF FO 3-Year MYP 50.50% PECO(8) (1) 10.95% / CF IT RT EH FO $68.7M Jun 2021 Gas 53.38% CF Rate case filed RT Rebuttal testimony IB Initial briefs FO Final commission order IT Intervenor direct testimony EH Evidentiary hearings RB Reply briefs SA Settlement agreement Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission, Maryland Public Service Commission, Pennsylvania Public Utility Commission, Delaware Public Service Commission, Public Service Commission of the District of Columbia, and New Jersey Board of Public Utilities that are subject to change (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement in initial filing was a decrease of ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. (3) Reflects 3-year cumulative multi-year plan. Company proposed incremental revenue requirement increases of $0.0M, $0.0M and $228.1M with rates effective January 1, 2021, January 1, 2022 and January 1, 2023, respectively. The proposed revenue requirement in 2023 reflects $137.0M increase for electric and $91.1M increase for gas. BGE’s proposal is accomplished through a series of proforma revenue requirement adjustments to accelerate certain tax benefits, among other things. (4) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. (5) Requested revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund. (6) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. (7) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $55.9M and $54.2M with rates effective April 1, 2023 and April 1, 2024, respectively. (8) Anticipated schedule, actual dates will be determined by ALJ at prehearing conference 11 Q3 2020 Earnings Release Slides


 

Featured Utility Capital Investments Pepco’s Streetlight Modernization Project in Maryland • Forecasted project cost: − $53 million • In service date: − Expected installation in Q1 2022 – Q4 2026 • Project scope: − Conversion of ~66,000 Maryland streetlights to Smart LEDs and integration of a Central Management System − Smart LED technology will reduce annual energy consumption by 60% - 80% and save approximately 119,500 tons of CO2 over the life of the streetlight − Integration of Smart LED streetlights into existing AMI communications network will enable future capabilities such as pollution monitors, traffic sensors and gunshot detectors − Automatic notifications from the streetlights to the Central Management System will improve outage response time and maintenance efficiency Exelon Utilities’ Customer Information System Transformation • Forecasted project cost: − $130 million • In service date: − Completed in September 2020 • Project scope: − Upgrade of BGE’s Customer Care and Billing System and implementation of Oracle’s Customer Experience Service Cloud at BGE, ComEd and PECO − Implementation of a service-oriented front-end platform drives operational efficiencies and improved customer satisfaction − Enhancing existing systems to a more-standardized, cloud-based interface enables greater flexibility and more efficient integration of future strategic capabilities 12 Q3 2020 Earnings Release Slides


 

Exelon Generation: Gross Margin* Update Change from September 30, 2020 June 30, 2020 Gross Margin Category ($M)(1) 2020 2021 2020 2021 Open Gross Margin*(2,5) $2,750 $3,550 $(100) - (including South, West, New England, Canada hedged gross margin) Capacity and ZEC Revenues(2) $1,900 $1,800 - - Mark-to-Market of Hedges(2,3) $1,850 $250 $250 $(100) Power New Business / To Go $100 $550 $(100) $(50) Non-Power Margins Executed $400 $250 $50 - Non-Power New Business / To Go $50 $250 $(50) - Total Gross Margin*(4,5) $7,050 $6,650 $50 $(150) Recent Developments • 2020 Total Gross Margin* is projected to be $50M higher primarily due to favorable Q3 weather and cost to serve • 2021 Total Gross Margin* is projected to be $150M lower primarily due to the retirements of Byron and Dresden, which is offset by $100M of O&M, $25M of D&A and $25M of TOTI savings related to the plant closures(5) • Executed a combined $200M of power and non-power new business in 2020 and $50M of power new business in 2021 • Behind ratable hedging position: ― ~2-5% behind ratable in 2021 when considering cross commodity hedges (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2020 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. See Additional ExGen Modeling Data (slide 36) for P&L offsets from the plant retirements. 13 Q3 2020 Earnings Release Slides


 

Maintaining Strong Investment Grade Credit Ratings is a Top Financial Priority Exelon S&P FFO/Debt %*(1) ExGen Debt/EBITDA Ratio*(2) 25% 4.0 19%-21% 20% 18% 3.0x S&P Threshold 3.0 15% 2.3x 1.9x 2.0 Book 10% Excluding Non-Recourse 5% 1.0 0% 0.0 2020 Target 2020 Target Credit Ratings by Operating Company Current Ratings(3) ExCorp ExGen ComEd PECO BGE ACE DPL Pepco Moody’s Baa2 Baa2 A1 Aa3 A3 A2 A2 A2 S&P BBB BBB+ A A A A A A Fitch BBB+ BBB A A+ A A- A A- (1) Exelon Corp downgrade threshold (orange dotted line) is based on the S&P Exelon Corp Summary Report; represents minimum level to maintain current Issuer Credit Rating at Exelon Corp (2) Reflects net book debt (YE debt less cash on hand) / adjusted operating EBITDA* (3) Current senior unsecured ratings as of September 30, 2020, for Exelon, Exelon Generation and BGE and senior secured ratings for ComEd, PECO, ACE, DPL, and Pepco 14 Q3 2020 Earnings Release Slides


 

The Exelon Value Proposition ▪ Regulated Utility Growth targeting utility EPS rising 6-8% annually from 2019- 2023 and rate base growth of 7.3%, representing an expanding majority of earnings ▪ ExGen’s free cash generation will support utility growth, ExGen debt reduction, and the external dividend ▪ 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 2023 planning horizon ▪ Capital allocation priorities targeting: • Organic utility growth; • Return of capital to shareholders with 5% annual dividend growth through 2020(1); and, • Debt reduction (1) Quarterly dividends are subject to declaration by the board of directors 15 Q3 2020 Earnings Release Slides


 

Additional Disclosures 16 Q3 2020 Earnings Release Slides


 

Q3 2020 YTD Adjusted Operating Earnings* Waterfall ($0.01) Unfavorable Weather ($0.05) Storm Costs(2) ($0.01) Storm Costs(2) ($0.02) Unfavorable Weather ($0.02) Depreciation & Amortization $0.01 Other ($0.01) Depreciation & Amortization $0.05 Distribution and Transmission Rate Increases ($0.01) Other ($0.02) Other $2.46 $2.39 $0.01 ($0.03) $0.17 ($0.09) $0.02 ($0.01) ($0.01) Distribution Investment(1) ($0.02) Other $0.16 Lower Operating and Maintenance Expense(3) $0.04 Distribution Rate Increase $0.11 Income Taxes ($0.02) Depreciation & Amortization $0.03 Depreciation and Amortization $0.02 Nuclear Fuel Cost $0.02 Higher Realized NDT Fund Gains $0.01 Zero Emission Credit Revenue (4) ($0.05) Nuclear Outages(5) ($0.07) Market and Portfolio Conditions(6) ($0.15) Capacity Revenues $0.09 Other(7) 2019 ComEd PECO BGE PHI ExGen(8) Corp 2020 Note: Amounts may not sum due to rounding (1) Reflects lower allowed electric distribution ROE due to a decrease in treasury rates, partially offset by higher rate base (2) At PECO, primarily reflects increased costs attributable to the June 2020 and August 2020 storms, net of tax repairs. At PHI, primarily reflects increased costs attributable to the August 2020 storm. (3) Includes the impacts of previous cost management programs, lower contracting costs and lower travel costs (4) Primarily reflects the approval of the New Jersey ZEC Program in the second quarter of 2019 (5) Reflects the revenue and operating and maintenance expense impacts of higher nuclear outage days in 2020, excluding Salem, partially offset by the impacts of lower nuclear outage days at Salem in 2020 (6) Primarily reflects reduction in load due to mild weather in the first quarter of 2020 and COVID-19, partially offset by higher portfolio optimization (7) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (8) Drivers reflect CENG ownership at 100% 17 Q3 2020 Earnings Release Slides


 

2020 Projected Sources and Uses of Cash (1) All amounts rounded to the nearest Total Cash ($M)(1) BGE ComEd PECO PHI ExGen Corp(9) Exelon $25M. Figures may not sum due to Utilities Balance rounding. Beginning Cash Balance*(2) 1,500 (2) Gross of posted counterparty Adjusted Cash Flow from Operations(2) 800 1,250 850 900 3,800 3,500 (350) 6,950 collateral Base CapEx and Nuclear Fuel(3) - - - - - (1,525) (125) (1,650) (3) Figures reflect cash CapEx and Free Cash Flow* 800 1,250 850 900 3,800 1,975 (475) 5,300 CENG fleet at 100% Debt Issuances 400 1,000 350 500 2,250 900 2,000 5,150 (4) Proceeds from securitization of Debt Retirements - (500) - - (500) (2,500) (900) (3,900) Constellation Accounts Receivable Portfolio Project Financing - - - - - (125) - (125) Equity Issuance/Share Buyback - - - - - - - - (5) Other primarily includes expected changes in commercial paper, tax AR Securitization(4) - - - - - 500 - 500 sharing from the parent, renewable Contribution from Parent 400 725 225 250 1,600 - (1,600) - JV distributions, tax equity cash Other(5) (75) 300 100 200 550 150 (250) 450 flows, debt issuance costs and Financing*(6) 725 1,525 700 950 3,900 (1,075) (750) 2,050 other financing activities Total Free Cash Flow and Financing* 1,550 2,775 1,550 1,850 7,700 875 (1,225) 7,350 (6) Financing cash flow excludes Utility Investment (1,300) (2,325) (1,200) (1,625) (6,450) - - (6,450) intercompany dividends ExGen Growth(3,7) - - - - - (125) - (125) (7) ExGen Growth CapEx primarily Acquisitions and Divestitures - - - - - - - - includes Retail Solar and W. Equity Investments - - - - - 50 - 50 Medway Dividend(8) - - - - - - - (1,500) (8) Dividends are subject to declaration Other CapEx and Dividend (1,300) (2,325) (1,200) (1,625) (6,450) (75) - (8,000) by the Board of Directors Total Cash Flow* 250 425 350 225 1,275 825 (1,225) (650) (9) Includes cash flow activity from Ending Cash Balance*(2) 875 Holding Company, eliminations and other corporate entities Consistent and reliable free cash flows Supported by a strong balance sheet Enable growth & value creation Operational excellence and financial Strong balance sheet enables flexibility to Creating value for customers, discipline drives free cash flow* reliability raise and deploy capital for growth communities and shareholders ✓ Generating $5,300M of free cash flow*, ✓ $1,750M of long-term debt at the utilities, ✓ Investing $6,575M of growth CapEx, with including $1,975M at ExGen and $3,800M net of refinancing, to support continued $6,450M at the Utilities and $125M at at the Utilities growth ExGen ✓ Retirement of $1,600M long-term debt at ExGen, net of refinancing and excluding A/R Securitization and Project Financing 18 Q3 2020 Earnings Release Slides


 

Exelon Debt Maturity Profile(1,2) As of 9/30/2020 LT Debt Balances (as of 9/30/20)(1,2) ($M) BGE 3.7B ComEd 9.2B PECO 3.9B PHI 7.0B ExGen recourse(3) 4.9B ExGen non-recourse 1.8B 910 HoldCo 7.4B Consolidated 38.0B 500 1,023 600 1,650 1,2251,200 900 850 600 2,150 1,190 175 1,550 1,430 1,400 1,250 1,275 1,150 997 850 833 833 900 807 750 763 788 741 750 750 185 675 700 650 550 360 350 300 303 258 295 78 2020 2021 2022 2023 2024 2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045 2046 2047 2048 2049 2050 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon’s weighted average LTD maturity is approximately 16 years (1) Maturity profile excludes non-recourse debt, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q3 2020 10-Q GAAP financials, which include items listed in footnote 1. On October 2, 2020, ExGen retired $550M of legacy CEG debt. (3) Includes legacy CEG debt of $550M and $258M in 2020 and 2032 19 Q3 2020 Earnings Release Slides


 

Exelon Utilities 20 Q3 2020 Earnings Release Slides


 

ComEd Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0393 • April 16, 2020, ComEd filed its annual distribution formula rate update with the Illinois Test Year January 1, 2019 – December 31, 2019 Commerce Commission seeking a decrease to Test Period 2019 Actual Costs + 2020 Projected Plant distribution base rates. A Final Order is Additions expected in early December. • October 14, 2020, draft proposed orders were Proposed Common Equity Ratio 48.16% filed by ComEd, ICC Staff and intervenors Proposed Rate of Return ROE: 8.38%; ROR: 6.28% • A final Order from the Commission is expected in early December Proposed Rate Base (Adjusted) $12,051M Requested Revenue Requirement Decrease ($13.6M)(1,2) Residential Total Bill % Decrease (1.3%) Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Filed rate case 4/16/2020 Intervenor testimony 6/30/2020 Rebuttal testimony 7/28/2020 Evidentiary hearings 9/10/2020 Initial briefs 9/28/2020 Reply briefs 10/13/2020 Commission order expected 12/2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement in initial filing was a decrease of ($11.5M). Through the discovery period in the current proceeding, ComEd agreed to ~($2.1M) in adjustments to limit issues in the case. 21 Q3 2020 Earnings Release Slides


 

BGE Distribution Rate Case Filing Multi-Year Plan Case Filing Details Notes Formal Case No. 9645 • May 15, 2020, BGE filed a three year multi-year plan (MYP) request with the Maryland Public Test Year January 1 – December 31 Service Commission (MDPSC) seeking an Test Period 2021, 2022, 2023 increase in electric and gas distribution base rates Proposed Common Equity Ratio 52.00% • Size of ask is driven by continued investments in electric and gas distribution system to 2021-2023 Proposed Rate of Return ROE: 10.10%, 10.10%, 10.10% maintain and increase reliability and customer ROR: 7.09%, 7.10%, 7.09% service 2021-2023 Proposed Rate Base (Adjusted) $6.5B, $7.1B, $7.7B • In light of COVID-19 pandemic, MYP includes measures to mitigate revenue requirement (1,2) 2021-2023 Requested Revenue Requirement Increase $0.0M, $0.0M, $228.1M needs while preserving BGE’s ability to execute (2) its capital and O&M plans and earn the 2021-2023 Residential Total Bill % Increase 0.0%, 0.0%, 8.0% authorized return(3) Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Filed rate case 5/15/2020 Intervenor testimony 8/14/2020 Rebuttal testimony 9/11/2020 Evidentiary hearings 10/13/2020 - 10/21/2020 Initial briefs 11/4/2020 Reply briefs 11/12/2020 Commission order expected 12/16/2020 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Company proposed incremental revenue requirement increases with rates effective January 1, 2021, January 1, 2022 and January 1, 2023, respectively. The proposed revenue requirement in 2023 reflects $137.0M increase for electric and $91.1M increase for gas. (3) Measures include decreasing a performance adder included in its recommended return on equity and proposing a series of proforma adjustments to change the method for recovery of major storm costs, accelerate certain tax benefits, suspend regulatory asset amortization in 2021 and extend the amortization periods of certain existing regulatory assets 22 Q3 2020 Earnings Release Slides


 

Pepco DC Distribution Rate Case Filing Multi-Year Plan Case Filing Details Notes Formal Case No. 1156 • May 30, 2019, Pepco DC filed a three year multi-year plan (MYP) request with the Public Test Year January 1 – December 31 Service Commission of the District of Columbia Test Period 2020, 2021, 2022 (DCPSC) seeking an increase in electric distribution base rates Proposed Common Equity Ratio 50.68% • MYP proposes five tracking Performance Incentive Mechanisms (PIMs) focused on Proposed Rate of Return ROE: 9.70%; ROR: 7.39% system reliability, customer service and 2020-2022 Proposed Rate Base (Adjusted) $2.2B, $2.4B, $2.6B interconnection Distributed Energy Resources (1,2) (DER) 2020-2022 Requested Revenue Requirement Increase $0.0M, $0.0M, $72.6M, $63.3M • June 1, 2020, Pepco DC filed MYP Enhanced (2) 2020-2022 Residential Total Bill % Increase 0.0%, 0.0%, 4.6%, 6.6% Proposal to address impact of COVID-19. The proposal includes an offset to distribution rates allowing for no overall distribution increase until January 2022 and several customer assistance programs. Detailed Rate Case Schedule May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Filed rate case 5/30/2019 Intervenor testimony 3/6/2020 Rebuttal testimony 4/8/2020 Evidentiary hearings 10/26/2020 - 10/30/2020 Initial briefs 12/9/2020 Reply briefs 12/23/2020 Commission order expected Q1 2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects 3-year cumulative multi-year plan for 2020-2022. Company proposed incremental revenue requirement increases of $72.6M and $63.3M with rates effective January 1, 2022 and January 1, 2023, respectively. 23 Q3 2020 Earnings Release Slides


 

Delmarva DE (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0150 • February 21, 2020, Delmarva Power filed an application with the Delaware Public Service Test Year April 1, 2019 – March 31, 2020 Commission (DPSC) seeking an increase in gas Test Period 9 months actual + 3 months estimated distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 50.37% in gas distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.15% increase reliability and customer service Proposed Rate Base (Adjusted) $399.7M Requested Revenue Requirement Increase $7.2M(1,2) Residential Total Bill % Increase 4.7% Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr Filed rate case 2/21/2020 Intervenor testimony 9/1/2020 Rebuttal testimony 10/9/2020 Evidentiary hearings 12/3/2020 - 12/4/2020 Initial briefs 1/11/2021 Reply briefs 1/29/2021 Commission order expected Q1 2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $4.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on September 21, 2020, subject to refund. 24 Q3 2020 Earnings Release Slides


 

Delmarva DE (Electric) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Test Year April 1, 2019 – March 31, 2020 Commission (DPSC) seeking an increase in Test Period 9 months actual + 3 months estimated electric distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 50.37% in electric distribution system to maintain and Proposed Rate of Return ROE: 10.30%; ROR: 7.15% increase reliability and customer service Proposed Rate Base (Adjusted) $922.1M Requested Revenue Requirement Increase $24.0M(1,2) Residential Total Bill % Increase 3.5% Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Filed rate case 3/6/2020 Intervenor testimony 9/9/2020 Rebuttal testimony 10/26/2020 Evidentiary hearings 2/11/2021 - 2/12/2021 Initial briefs Reply briefs Commission order expected Q2 2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Requested revenue requirement excludes the transfer of $3.4M of revenues from the Distribution System Improvement Charge (DSIC) capital tracker into base distribution rates. As permitted by Delaware law, Delmarva Power implemented full allowable rates on October 6, 2020, subject to refund. 25 Q3 2020 Earnings Release Slides


 

Pepco MD Distribution Rate Case Filing Multi-Year Plan Case Filing Details Notes Formal Case No. 9655 • October 26, 2020, Pepco MD filed a three-year multi-year plan (MYP) request with the Maryland Test Year April 1 – March 31 Public Service Commission (MDPSC) seeking an Test Period 2022, 2023, 2024 increase in electric distribution base rates • MYP proposes five tracking only Performance Proposed Common Equity Ratio 50.50% Incentive Mechanisms (PIMs) focused on system reliability, customer service and Proposed Rate of Return ROE: 10.20%; ROR: 7.54% environmental 2022-2024 Proposed Rate Base (Adjusted) $2.4B, $2.6B, $2.8B • The proposal includes an offset to distribution (1,2) rates allowing for no overall distribution 2022-2024 Requested Revenue Requirement Increase $0.0M, $0.0M, $55.9M, $54.2M increase until April 2023 (2) 2022-2024 Residential Total Bill % Increase 0.0%, 0.0%, 4.4%, 4.2% Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Reply briefs Commission order expected 5/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Reflects 3-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. Company proposed incremental revenue requirement increases of $55.9M and $54.2M with rates effective April 1, 2023 and April 1, 2024, respectively. 26 Q3 2020 Earnings Release Slides


 

PECO (Gas) Distribution Rate Case Filing Rate Case Filing Details Notes Docket No. R-2020-3018929 • On September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Test Year July 1, 2021 – June 30, 2022 Utility Commission (PAPUC) seeking an increase Test Period 12 Months Budget in gas distribution base rates • Size of ask is driven by continued investments Proposed Common Equity Ratio 53.38% in gas distribution system to maintain and Proposed Rate of Return ROE: 10.95%; ROR: 7.70% increase safety, reliability and customer service Proposed Rate Base (Adjusted) $2,462M Requested Revenue Requirement Increase $68.7M(1) Residential Total Bill % Increase 9.0% Detailed Rate Case Schedule(2) Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 9/30/2020 Intervenor testimony 12/2020 Rebuttal testimony 1/2021 Evidentiary hearings 2/2021 Commission order expected 6/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Anticipated schedule, actual dates will be determined by ALJ at prehearing conference 27 Q3 2020 Earnings Release Slides


 

Exelon Generation Disclosures September 30, 2020 28 Q3 2020 Earnings Release Slides


 

Portfolio Management Strategy Align Hedging & Financials Portfolio Management Over Time Exercising Market Views Establishing Minimum Hedge Targets % Hedged High End of Profit Low End of Profit Purely ratable Capital Credit Rating Structure Actual hedge % % Hedged % Capital & Market views on timing, product Operating Dividend allocation and regional spreads Expenditure Open Generation Portfolio Management & reflected in actual hedge % with LT Contracts Optimization Protect Balance Sheet Ensure Earnings Stability Create Value 29 Q3 2020 Earnings Release Slides


 

Components of Gross Margin* Categories Gross margin* from Gross margin* linked to power production and sales other business activities Open Gross Capacity and ZEC MtM of “Power” New “Non Power” “Non Power” Margin* Revenues Hedges(2) Business Executed New Business •Generation Gross •Expected capacity •Mark-to-Market •Retail, Wholesale •Retail, Wholesale •Retail, Wholesale Margin* at current revenues for (MtM) of power, planned electric executed gas sales planned gas sales market prices, generation of capacity and sales •Energy •Energy including ancillary electricity ancillary hedges, •Portfolio Efficiency(4) Efficiency(4) revenues, nuclear •Expected including cross Management new •BGE Home(4) •BGE Home(4) fuel amortization commodity, retail revenues from business •Distributed Solar •Distributed Solar and fuels expense Zero Emissions and wholesale •Mid marketing •Portfolio •Power Purchase Credits (ZEC) load transactions new business Management / Agreement (PPA) •Provided directly origination fuels Costs and at a consolidated new business Revenues level for four major •Proprietary •Provided at a regions. Provided trading(3) consolidated level indirectly for each for all regions of the four major (includes hedged regions via gross margin* for Effective Realized South, West, New Energy Price England and (EREP), reference Canada(1)) price, hedge %, expected generation. Margins move from new business to MtM of Margins move from “Non power new business” to hedges over the course of the year as sales “Non power executed” over the course of the are executed(5) year (1) Hedged gross margins* for South, West, New England & 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 four 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, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin* 30 Q3 2020 Earnings Release Slides


 

ExGen Disclosures September 30, 2020 Gross Margin Category ($M)(1) 2020 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)*(2,5) $2,750 $3,550 Capacity and ZEC Revenues(2) $1,900 $1,800 Mark-to-Market of Hedges(2,3) $1,850 $250 Power New Business / To Go $100 $550 Non-Power Margins Executed $400 $250 Non-Power New Business / To Go $50 $250 Total Gross Margin*(4,5) $7,050 $6,650 Reference Prices(4) 2020 2021 Henry Hub Natural Gas ($/MMBtu) $2.06 $2.92 Midwest: NiHub ATC prices ($/MWh) $19.22 $24.68 Mid-Atlantic: PJM-W ATC prices ($/MWh) $21.31 $28.67 ERCOT-N ATC Spark Spread ($/MWh) $3.71 $8.00 HSC Gas, 7.2HR, $2.50 VOM New York: NY Zone A ($/MWh) $18.80 $26.51 (1) Gross margin* categories rounded to nearest $50M (2) Excludes EDF’s equity ownership share of the CENG Joint Venture (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on September 30, 2020 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively 31 Q3 2020 Earnings Release Slides


 

ExGen Disclosures September 30, 2020 Generation and Hedges 2020 2021 Expected Generation (GWh)(1) 179,500 173,000 Midwest(6) 97,900 87,900 Mid-Atlantic(2) 47,900 47,900 ERCOT 18,100 20,600 New York(2) 15,600 16,600 % of Expected Generation Hedged(3) 97%-100% 87%-90% Midwest(6) 97%-100% 88%-91% Mid-Atlantic(2) 98%-101% 88%-91% ERCOT 97%-100% 87%-90% New York(2) 95%-98% 80%-83% Effective Realized Energy Price ($/MWh)(4) Midwest(6) $28.00 $25.50 Mid-Atlantic(2) $36.50 $31.50 ERCOT(5) $10.50 $9.00 New York(2) $30.50 $27.50 (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2020 and 11 in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factors of 95.1% and 94.6% in 2020 and 2021, respectively at Exelon-operated nuclear plants, at ownership. These estimates of expected generation in 2021 do not represent guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years. (2) Excludes EDF’s equity ownership share of CENG Joint Venture (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. Includes all hedging products, such as wholesale and retail sales of power, options and swaps. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the fossil fuel that has been purchased to lock in margin. It excludes uranium costs, RPM capacity and ZEC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to-market value of Exelon Generation's energy hedges. (5) Spark spreads shown for ERCOT (6) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively 32 Q3 2020 Earnings Release Slides


 

ExGen Hedged Gross Margin* Sensitivities September 30, 2020 Gross Margin* Sensitivities (with existing hedges)(1,2) 2020 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $40 $235 - $1/MMBtu $(35) $(170) NiHub ATC Energy Price + $5/MWh - $40 - $5/MWh - $(40) PJM-W ATC Energy Price + $5/MWh $5 $35 - $5/MWh $(5) $(30) NYPP Zone A ATC Energy Price + $5/MWh $5 $10 - $5/MWh $(5) $(10) Nuclear Capacity Factor +/- 1% +/- $5 +/- $30 (1) Based on September 30, 2020 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 (2) These sensitivities do not capture changes to underlying assumptions for COVID-19 33 Q3 2020 Earnings Release Slides


 

ExGen Hedged Gross Margin* Upside/Risk 8,000 7,500 (1) $7,100 7,000 $6,950 $7,000 6,500 $6,400 6,000 Approximate Gross ($ Margin* million) Gross Approximate 5,500 5,000 2020 2021 (1) Represents an approximate range of expected gross margin*, taking into account hedges in place, between the 5th and 95th percent confidence levels assuming all unhedged supply is sold into the spot market; approximate gross margin* ranges are based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; these ranges of approximate gross margin* in 2021 do not represent earnings guidance or a forecast of future results as Exelon has not completed its planning or optimization processes for those years; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of September 30, 2020. Gross Margin* Upside/Risk based on commodity exposure which includes open generation and all committed transactions. Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively. 34 Q3 2020 Earnings Release Slides


 

Illustrative Example of Modeling Exelon Generation 2021 Total Gross Margin* Row Item Midwest Mid-Atlantic ERCOT New York (A) Start with fleet-wide open gross margin* $3.55 billion (B) Capacity and ZEC $1.8 billion (C) Expected Generation (TWh) 87.9 47.9 20.6 16.6 (D) Hedge % (assuming mid-point of range) 89.5% 89.5% 88.5% 81.5% (E=C*D) Hedged Volume (TWh) 78.7 42.9 18.2 13.5 (F) Effective Realized Energy Price ($/MWh) $25.50 $31.50 $9.00 $27.50 (G) Reference Price ($/MWh) $24.68 $28.67 $8.00 $26.51 (H=F-G) Difference ($/MWh) $0.82 $2.83 $1.00 $0.99 (I=E*H) Mark-to-Market value of hedges ($ million)(1) $65 $125 $20 $15 (J=A+B+I) Hedged Gross Margin ($ million) $5,600 (K) Power New Business / To Go ($ million) $550 (L) Non-Power Margins Executed ($ million) $250 (M) Non-Power New Business / To Go ($ million) $250 (N=J+K+L+M) Total Gross Margin* $6,650 million (1) Mark-to-market rounded to the nearest $5M 35 Q3 2020 Earnings Release Slides


 

Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2020 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,450 $7,075 Other Revenues(4) $(175) $(150) Direct cost of sales incurred to generate revenues for certain $(225) $(275) Constellation and Power businesses Total Gross Margin* (Non-GAAP) $7,050 $6,650 Key ExGen Modeling Inputs (in $M)(1,5) 2020 2021 Other(6) $225 $125 Adjusted O&M*(7) $(4,000) $(4,050) Taxes Other Than Income (TOTI)(8) $(375) $(350) Depreciation & Amortization* $(1,025) $(1,050) Interest Expense $(325) $(325) Effective Tax Rate 20.0% 23.0% (1) All amounts rounded to the nearest $25M (2) ExGen does not forecast the GAAP components of RNF separately, as to do so would be unduly burdensome. RNF also includes the RNF of our proportionate ownership share of CENG. (3) Excludes the Mark-to-Market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (6) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, and includes the minority interest in ExGen Renewables JV (7) 2020 and 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time (8) 2020 and 2021 TOTI excludes gross receipts tax of $125M 36 Q3 2020 Earnings Release Slides


 

Appendix Reconciliation of Non-GAAP Measures 37 Q3 2020 Earnings Release Slides


 

Q3 QTD GAAP EPS Reconciliation Three Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.20 $0.14 $0.05 $0.22 $0.05 ($0.16) $0.51 Mark-to-market impact of economic hedging activities - - - - (0.20) 0.01 (0.19) Unrealized gains related to NDT funds - - - - (0.18) - (0.18) Asset Impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.34 - 0.34 Cost management program - - - - 0.01 - 0.02 Change in environmental liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - - - - 0.01 - 0.01 Income tax-related adjustments - - - - (0.03) 0.09 0.06 Noncontrolling interests - - - - 0.06 - 0.06 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.20 $0.14 $0.06 $0.23 $0.47 ($0.05) $1.04 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 38 Q3 2020 Earnings Release Slides


 

Q3 QTD GAAP EPS Reconciliation (continued) Three Months Ended September 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.21 $0.14 $0.06 $0.19 $0.26 ($0.07) $0.79 Mark-to-market impact of economic hedging activities - - - - (0.01) 0.01 - Unrealized gains related to NDT funds - - - - (0.04) - (0.04) Asset Impairments - - - - 0.12 - 0.12 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - - 0.01 - 0.01 Asset retirement obligation - - - - (0.09) - (0.09) Change in environmental liabilities - - - 0.02 - - 0.02 Income Tax-Related Adjustments - - - - 0.01 - 0.01 Noncontrolling interests - - - - (0.02) - (0.02) 2019 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.21 $0.14 $0.06 $0.21 $0.36 ($0.06) $0.92 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 39 Q3 2020 Earnings Release Slides


 

Q3 YTD GAAP EPS Reconciliation Nine Months Ended September 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.31 $0.32 $0.28 $0.43 $0.58 ($0.28) $1.64 Mark-to-market impact of economic hedging activities - - - - (0.36) 0.02 (0.34) Unrealized losses related to NDT funds - - - - 0.01 - 0.01 Asset Impairments 0.01 - - - 0.39 - 0.40 Plant retirements and divestitures - - - - 0.36 - 0.36 Cost management program - - - 0.01 0.03 - 0.03 Change in Environmental Liabilities - - - - 0.02 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.04 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income Tax-Related Adjustments - - - - (0.03) 0.10 0.07 Noncontrolling interests - - - - 0.02 - 0.02 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per $0.53 $0.33 $0.29 $0.44 $1.04 ($0.17) $2.46 Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 40 Q3 2020 Earnings Release Slides


 

Q3 YTD GAAP EPS Reconciliation (continued) Nine Months Ended September 30, 2019 ComEd PECO BGE PHI ExGen Other Exelon 2019 GAAP Earnings (Loss) Per Share $0.56 $0.42 $0.27 $0.42 $0.75 ($0.20) $2.22 Mark-to-market impact of economic hedging activities - - - - 0.08 0.02 0.10 Unrealized gains related to NDT funds - - - - (0.19) - (0.19) Asset Impairments - - - - 0.12 - 0.12 Plant retirements and divestitures - - - - 0.12 - 0.12 Cost management program - - - - 0.02 - 0.03 Litigation settlement gain - - - - (0.02) - (0.02) Asset retirement obligation - - - - (0.09) - (0.09) Change in environmental liabilities - - - 0.02 - - 0.02 Income Tax-Related Adjustments - - - - 0.01 - 0.01 Noncontrolling interests - - - - 0.06 - 0.06 2019 Adjusted (non-GAAP) Operating Earnings (Loss) $0.56 $0.42 $0.27 $0.45 $0.87 ($0.18) $2.39 Per Share Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding. 41 Q3 2020 Earnings Release Slides


 

Projected GAAP to Operating Adjustments • Exelon’s projected 2020 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 funds to the extent not offset by contractual accounting as described in the notes to the consolidated financial statements; − Asset impairments; − Certain costs related to plant retirements; − Certain costs incurred to achieve cost management program savings; − Certain costs related to changes in environmental liabilities; − Direct costs related to COVID-19; − Deferred Prosecution Agreement payments; − Update to long term state tax marginal rates; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to CENG exclusion items. 42 Q3 2020 Earnings Release Slides


 

GAAP to Non-GAAP Reconciliations(1) (2) Exelon FFO/Debt = FFO (a) Adjusted Debt (b) Exelon FFO Calculation(2) GAAP Operating Income + Depreciation & Amortization = EBITDA - Interest Expense +/- Cash Taxes + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) Exelon Adjusted Debt Calculation(1) Long-Term Debt (including current maturities) + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Pension/OPEB Imputed Debt (after-tax) + AR Securitization Imputed Debt - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) (1) 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; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology 43 Q3 2020 Earnings Release Slides


 

GAAP to Non-GAAP Reconciliations(1) ExGen Debt/EBITDA = Net Debt (a) ExGen Debt/EBITDA = Net Debt (c) Operating EBITDA (b) Excluding Non-Recourse Operating EBITDA (d) ExGen Net Debt Calculation ExGen Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) ExGen Operating EBITDA Calculation ExGen Operating EBITDA Calculation Excluding Non- Recourse GAAP Operating Income + Depreciation & Amortization GAAP Operating Income = EBITDA + Depreciation & Amortization +/- GAAP to Operating Adjustments = EBITDA = Operating EBITDA (b) +/- GAAP to Operating Adjustments - EBITDA from Projects Financed by Non-Recourse Debt = Operating EBITDA Excluding Non-Recourse (d) (1) 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; therefore, management is unable to reconcile these measures 44 Q3 2020 Earnings Release Slides


 

GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,747 $1,728 $2,060 Operating Exclusions 243 $254 $31 Adjusted Operating Earnings 1,990 $1,982 $2,091 Average Equity 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2019 Q3 2019 Q2 2019 Q1 2019 Net Income (GAAP) $2,065 $2,037 $2,011 $1,967 Operating Exclusions $30 $33 $31 $33 Adjusted Operating Earnings $2,095 $2,070 $2,042 $1,999 Average Equity $20,913 $20,500 $20,111 $19,639 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 10.0% 10.1% 10.2% 10.2% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Q1 2018 Net Income (GAAP) $1,836 $1,770 $1,724 $1,643 Operating Exclusions $32 $40 $13 $32 Adjusted Operating Earnings $1,869 $1,810 $1,737 $1,675 Average Equity $19,367 $18,878 $18,467 $17,969 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% 9.3% Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2017 Net Income (GAAP) $1,704 Operating Exclusions ($24) Adjusted Operating Earnings $1,680 Average Equity $17,779 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.4% Note: Represents the twelve-month periods ending September 30, 2018-2020, June 30, 2018-2020, March 31, 2018-2020 and December 31, 2017-2019. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Q3 2019, Q2 2019, Q1 2019, Q4 2018, Q3 2018, Q2 2018, Q1 2018 and Q4 2017 TTM ROEs* for Consolidated EU were changed from 10.1%, 10.2%, 10.2%, 9.7%, 9.6%, 9.4%, 9.4% and 9.5%, respectively, to 10.1%, 10.2%, 10.2%, 9.6%, 9.6%, 9.4%, 9.3% and 9.4%, respectively, to reflect the correction of an error at PHI. 45 Q3 2020 Earnings Release Slides


 

GAAP to Non-GAAP Reconciliations 2020 Adjusted Cash from Ops Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flows provided by operating activities (GAAP) $800 $1,250 $850 $900 $2,425 ($350) $5,875 Other cash from investing activities - - - - ($250) - ($250) Counterparty collateral activity - - - - ($675) - ($675) A/R Securitization - - - - ($500) - ($500) (2) Collection of DPP - - - - $2,525 - $2,525 Adjusted Cash Flow from Operations (Non-GAAP) $800 $1,250 $850 $900 $3,500 ($350) $6,950 2020 Cash From Financing Calculation ($M)(1) BGE ComEd PECO PHI ExGen Other Exelon Net cash flow provided by financing activities (GAAP) $500 $1,025 $350 $575 ($3,150) $750 $50 Dividends paid on common stock $250 $500 $350 $375 $1,550 ($1,525) $1,500 A/R Securitization - - - - $500 - $500 Financing Cash Flow (Non-GAAP) $725 $1,525 $700 $950 ($1,075) ($750) $2,050 Exelon Total Cash Flow Reconciliation(1) 2020 GAAP Beginning Cash Balance $575 Adjustment for Cash Collateral Posted $925 Adjusted Beginning Cash Balance(3) $1,500 Net Change in Cash (GAAP)(4) ($625) Adjusted Ending Cash Balance(3) $875 Adjustment for Cash Collateral Posted ($275) GAAP Ending Cash Balance $600 (1) All amounts rounded to the nearest $25M. Items may not sum due to rounding. (2) Cash flows from the revolving accounts receivable financing arrangement (A/R Securitization) at ExGen are presented as cash flows from operating activities and cash flows from investing activities for GAAP, but as cash flows from operating activities for Adjusted (Non-GAAP) Cash Flows. The Collection of Deferred Purchase Price (DPP) in the table reflects the rounded amount of $2,518M for the nine months ended September 30, 2020, which is presented as cash flows from investing for GAAP. (3) Adjusted Beginning and Ending cash balances reflect GAAP Beginning and End Cash Balances excluding counterparty collateral activity (4) 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%. 46 Q3 2020 Earnings Release Slides


 

GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2020 2021 GAAP O&M $5,100 $4,700 Decommissioning(2) $75 $75 Byron, Dresden and Mystic 8/9 Retirements(3) ($425) ($25) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(4) ($225) ($275) O&M for managed plants that are partially owned ($400) ($425) Other ($150) - Adjusted O&M (Non-GAAP) $4,000 $4,050 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) 2020 includes $350M impact of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* 47 Q3 2020 Earnings Release Slides