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EXC Exelon Generation

Filed: 4 Aug 21, 6:53am
Earnings Conference Call Second Quarter 2021 August 4, 2021


 

2 Q2 2021 Earnings Release Slides Cautionary Statements Regarding Forward-Looking Information This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties including, among others, those related to the timing, manner, tax-free nature, and expected benefits associated with the potential separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. 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' 2020 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 19, Commitments and Contingencies; (2) the Registrants' Second Quarter 2021 Quarterly Report on Form 10-Q (to be filed on Aug. 4, 2021) 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 15, 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.


 

3 Q2 2021 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


 

4 Q2 2021 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.


 

5 Q2 2021 Earnings Release Slides Second Quarter Results • Received outcomes in our Pepco DC and MD multi-year plans • NJ BPU approved ACE settlement and PAPUC issued order in PECO Gas rate case • 22/23 PJM Base Residual Auction held • Zero-Emission Nuclear Power Production Credit Act of 2021 introduced in U.S. House and Senate Q2 2021 EPS Results Q2 2021 Highlights/Key Developments Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(1) $0.20 $0.20 $0.14 $0.15 $0.11 $0.11 ($0.06) $0.40 Q2 GAAP Earnings $0.05 ($0.02) $0.05 ($0.02) Q2 Adjusted Operating Earnings* $0.41 $0.89 Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M BGE HoldCo ExGen ComEd PHI PECO


 

6 Q2 2021 Earnings Release Slides Operating Highlights (1) 2.5 Beta SAIFI is YE projection (2) Excludes Salem and EDF’s equity ownership share of the CENG Joint Venture Exelon Utilities Operational Metrics Exelon Generation Operational Performance • Best in class performance across our Nuclear fleet: ― Q2 2021 Nuclear Capacity Factor: 93.7% ― Owned and operated Q2 2021 production of 36.6 TWh • Q2 2021 Power Dispatch Match: 99.5% • Q2 2021 Wind/Solar Energy Capture: 96.0% Operations Metric YTD 2021 BGE ComEd PECO PHI Electric Operations OSHA Recordable Rate 2.5 Beta SAIFI (Outage Frequency)(1) 2.5 Beta CAIDI (Outage Duration) Customer Operations Customer Satisfaction Abandon Rate Gas Operations Gas Odor Response No Gas Operations Fossil and Renewable Fleet Exelon Nuclear Fleet(2) 80% 82% 84% 86% 88% 90% 92% 94% 96% 98% 100% 30 32 34 36 38 40 42 44 Q3 20Q2 19 C a p a c ity F a c to r T W h rs Q2 20Q1 20Q3 19 Q4 19 Q4 20 Q1 21 Q2 21 Capacity FactorTWhrs Q1 Q2 Q3 Q4 Quartile • Reliability performance was strong across the utilities: ― BGE, ComEd and PHI delivered top decile CAIDI performance, and ComEd scored in the top decile in SAIFI • Each utility continued to deliver on key customer operations metrics: ― BGE, ComEd and PECO recorded top decile performance in customer satisfaction ― PHI achieved top decile performance in abandon rate • BGE, PECO and PHI performed in top decile in gas odor response • Focused on improving safety at BGE and PECO


 

7 Q2 2021 Earnings Release Slides Progress on Separation Commission Application Filing Key Regulatory Milestones New York Public Service Commission (NY PSC) (Case No. 21-E-0130) February 25, 2021 • Comments/intervention were due June 8, 2021 Federal Energy Regulatory Commission (FERC) (Docket No. EC21-57) February 25, 2021 • Initial comments/intervention were due March 18, 2021 • Subsequent comments/intervention were due May 13, 2021 Nuclear Regulatory Commission (NRC) February 25, 2021 • Comments were due June 23, 2021 • Deadline to request hearing closed July 12, 2021(1) • Estimated completion date by November 30, 2021 • Separation planning and preparation continues • Below is the current status of the regulatory filings: (1) Hearing requests may still be pending and resolved later


 

8 Q2 2021 Earnings Release Slides Exelon Utilities Path to Clean: Net-Zero by 2050 Invest in natural gas infrastructure modernization to minimize methane leakage Invest in our own vehicle fleet to deliver on our vehicle electrification targets Focus on energy efficiency and clean electricity for our operations Advocate for equitable policies that enable clean electric supply and low-carbon fuels for customers Invest in equipment and processes to reduce SF6 leakage from our systems Advance transportation electrification, energy efficiency programs and other technologies that modernize the grid Reducing our operations-driven emissions to net-zero... … while supporting our customers and communities in reaching clean energy goals Building on Exelon’s current company-wide commitment to reduce 15% of operations-driven emissions by 2022 and positioning the new Exelon Utilities organization to expand upon a transition to a clean energy economy 790,000 550,000 390,000 600,000 0 400,000 200,000 800,000 M e tr ic T o n s G H G E m is s io n s 2015 Baseline 2020 2030 Emissions Offsets 2050 Achieve net-zero operations by 2050 Cut operations-driven emissions in half by 2030


 

9 Q2 2021 Earnings Release Slides Barrier Elimination or Reduction Reduce or remove employment barriers faced by youth and work- ready adults in under-served and under-resourced communities Transforming Communities Through Our Workforce Development Strategy 1 STEM Education and Vocational Awareness Spark students’ interest in and knowledge of STEM and careers in the energy industry 2 Opportunity Creation and Partnerships Partner with employers, non-profits and community groups to expand training and job opportunities for youth and work-ready adults 3 Thought Leadership Drive positive community impact, develop and leverage best practices, and broadly share our successes 4 • More than 100 different workforce development programs across our 6 utilities and generation business seek to bring economic equity, empowerment and employment opportunity to our under-served and under-resourced communities – These programs have reached more than 22,000 participants and resulted in more than 1,400 hires • Exelon Utilities’ infrastructure academies develop technical skills and create pathways into full-time, family supporting careers – Launched first academy in Chicago in 2013; established academies in Washington D.C., Baltimore and Philadelphia in 2018-2020 – Since 2018, more than 65% of the 650 total graduates from Exelon’s various infrastructure academies were offered internal or external job opportunities • STEM Leadership Academies strengthen education and introduce the next generation of women to energy careers – 640 high school girls from our communities attended 11 academies since the program originated in 2018 – Annual STEM Leadership Academy Scholarship program covers all post-secondary education costs and guarantees internships with Exelon throughout college; 7 alumnae have been offered full-ride scholarships to two- or four-year colleges to date


 

10 Q2 2021 Earnings Release Slides $0.20 $0.15 $0.11 $0.05 $0.40 ($0.02) ComEd Q2 2021 PECO ExGen HoldCo BGE PHI $0.89 Second Quarter Adjusted Operating Earnings* Drivers Exelon Utilities • Utilities performed well in Q2 driven by continued investment and distribution rate case outcomes • No major storms • 30-Year Treasury rate declined since Q1 Exelon Generation • Unrealized and realized gains on equity investments (Constellation Technology Ventures) • NDT realized gains(1) • Strong nuclear performance • New business execution HoldCo • Partial reversal of Q1 tax expense Note: Amounts may not sum due to rounding (1) Gains related to unregulated sites (2) 2021 earnings guidance based on expected average outstanding shares of 980M Reaffirming 2021 Adjusted Operating Earnings* of $2.60 - $3.00 per share(2) Financial HighlightsQ2 2021 Adjusted Operating EPS* Results $0.49


 

11 Q2 2021 Earnings Release Slides Q2 2021 QTD Adjusted Operating Earnings* Waterfall $0.55 $0.89 $0.05 $0.06 $0.05 $0.14 ExGen(6)PECOComEd2020 BGE $0.01 $0.03 PHI Corp 2021 $0.10 Net Unrealized and Realized Gains on Equity Investments $0.04 Higher Realized NDT Fund Gains $0.03 Nuclear Outages(3) $0.02 ZEC Revenues ($0.05) Other(4) $0.01 Distribution and Transmission Rates $0.01 Favorable Load $0.01 Credit Loss Expense $0.02 Other Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the absence of costs in 2021 due to the June 2020 storms (3) Reflects operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (4) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (5) Reflects the reversal of part of the tax expense recorded in the first quarter due to the loss before income taxes at ExGen due to the February 2021 extreme cold weather event (6) Drivers reflect CENG ownership at 100% $0.04 Storm Costs(2) $0.01 Favorable Load $0.01 Other $0.01 Distribution Rates $0.02 Distribution Investment(1) $0.03 Other $0.04 Income Taxes(5) ($0.01) Other


 

12 Q2 2021 Earnings Release Slides Exelon Utilities Trailing Twelve Month Earned ROEs* Exelon Utilities’ Consolidated Trailing Twelve Month Earned ROEs* 9.4% 9.6% 9.6% 10.2% 10.2% 10.1% 10.0% 9.7% 9.1% 8.9% 8.7% 8.9% 9.4% Q4 2018Q2 2018 Q1 2020Q2 2019Q3 2018 Q1 2019 Q3 2019 Q4 2019 Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Note: Represents the twelve-month periods ending June 30, 2018-2021, March 31, 2019-2021, December 31, 2018-2020, and September 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission). Exelon Utilities’ Consolidated TTM Earned ROE* improved into our 9-10% targeted range primarily due to the roll-off of impacts from last year’s storms


 

13 Q2 2021 Earnings Release Slides Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Revenue Requirement Requested ROE / Equity Ratio Expected Order $108.6M (1,2) 3-Year MYP 9.275% / 50.68% Jun 8, 2021 $29.1M (1) 10.24% / 53.38% Jun 22, 2021 $52.2M (1,3) 3-Year MYP 9.55% / 50.50% Jun 28, 2021 $41.0M (1,4) 9.60% / 50.21% Jul 14, 2021 $22.9M (1,5) 10.30% / 50.37% Q3 2021 $246.0M (1) 10.95% / 53.41% Dec 2021 $45.9M (1,6) 7.36% / 48.70% Dec 2021 Exelon Utilities’ Distribution Rate Case Updates Rate Case Schedule and Key Terms Note: Unless otherwise noted, based on schedules of Illinois Commerce Commission (ICC), Maryland Public Service Commission (MDPSC), Pennsylvania Public Utility Commission (PAPUC), Delaware Public Service Commission (DPSC), Public Service Commission of the District of Columbia (DCPSC), and New Jersey Board of Public Utilities (NJBPU) 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) Reflects gross incremental revenue requirement increases (before offsets) for the remaining 18 months of the 3-year MYP of $41.7M and $66.9M with rates effective July 1, 2021, and January 1, 2022, respectively (3) Reflects gross incremental revenue requirement increases (before offsets) of $20.6M, $16.3M and $15.3M with rates effective June 28, 2021, April 1, 2022, and April 1, 2023, respectively (4) Reflects annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits. (5) 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. (6) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case. Pepco DC DPL DE Electric Pepco MD PECO Gas FOEH RBIB ACE Rate case filed Rebuttal testimony Initial briefs Final commission order Intervenor direct testimony Evidentiary hearings Reply briefs Settlement agreement CF IT RT EH IB RB FO SA FO PECO Electric ComEd RTIT EH IB RB CF FO FO RB RTIT EH IB RB FO FO FOSA


 

14 Q2 2021 Earnings Release Slides Exelon Generation: Gross Margin* Update (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 June 30, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. Recent Developments • 2021 Total Gross Margin* is projected to be flat primarily due to increased power prices, offset by our hedges – Executed $150M of Power New Business and $50M of Non-Power New Business for 2021 June 30, 2021 Change from March 31, 2021 Gross Margin Category ($M) (1) 2021 2021 Open Gross Margin* (2,5) (including South, West, New England, Canada hedged gross margin) $4,250 $750 Capacity and ZEC Revenues (2) $1,800 - Mark-to-Market of Hedges (2,3) $(100) $(600) Power New Business / To Go $250 $(150) Non-Power Margins Executed $350 $50 Non-Power New Business / To Go $150 $(50) Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 - Estimated Gross Margin Impact of February Weather Event (6) $(950) - Total Gross Margin* $5,750 -


 

15 Q2 2021 Earnings Release Slides 2021 Business Priorities and Commitments Meet or exceed our financial commitments Effectively deploy ~$6.6B of utility capex Ensure timely recovery on investments to enable customer benefits Support enactment of clean energy policies Continued demonstration of corporate responsibility Prepare for separation of businesses Maintain industry-leading operational excellence


 

16 Q2 2021 Earnings Release Slides Additional Disclosures


 

17 Q2 2021 Earnings Release Slides $0.55 - $0.85 $0.40 - $0.50 $0.55 - $0.65 $0.45 - $0.55 ($0.25) ComEd 2021 Guidance $0.75 - $0.85 ExGen BGE PECO PHI HoldCo $2.60 - $3.00(1) Reaffirming 2021 Adjusted Operating Earnings* Guidance Note: Amounts may not sum due to rounding (1) 2021 earnings guidance based on expected average outstanding shares of 980M


 

18 Q2 2021 Earnings Release Slides Q2 2021 YTD Adjusted Operating Earnings* Waterfall $0.09 BGE2020 $0.03 PECOComEd PHI ($0.76) ExGen(7) ($0.10) Corp 2021 $0.07 $1.42 $0.07 ($0.84) Market and Portfolio Conditions(3) ($0.14) Income Taxes(4) ($0.03) Credit Loss Expense(3) $0.12 Higher Realized NDT Fund Gains $0.08 Net Unrealized and Realized Gains on Equity Investments $0.08 Nuclear Outages(5) $0.03 ZEC Revenues $0.02 Capacity Revenues ($0.08) Other(6) $0.02 Distribution and Transmission Rates $0.02 Favorable Weather and Load $0.01 Credit Loss Expense $0.02 Other Note: Amounts may not sum due to rounding (1) Reflects higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates (2) Primarily reflects the absence of costs in 2021 due to the June 2020 storms (3) Primarily reflects the impacts of the February 2021 extreme cold weather event (4) ($0.06) at ExGen and the ($0.08) at Corp relate to timing of tax expense driven primarily by the loss before income taxes at ExGen in the first quarter due to the February 2021 extreme cold weather event. These timing impacts will continue to reverse by the end of the year. ($0.07) at ExGen reflects the absence of a prior year one-time tax settlement. (5) Reflects the revenue and operating and maintenance expense impacts of lower nuclear outage days in 2021, including Salem (6) Primarily reflects the elimination of activity attributable to noncontrolling interest, primarily for CENG (7) Drivers reflect CENG ownership at 100% $0.05 Favorable Weather and Load $0.04 Storm Costs(2) $0.83 $0.05 Distribution Rates ($0.02) Other $0.04 Distribution Investment(1) $0.03 Other ($0.08) Income Taxes(4) ($0.02) Other


 

19 Q2 2021 Earnings Release Slides Constellation Technology Ventures’ Active Investments Note: Constellation’s active technology investments can be found at http://technologyventures.constellation.com/; reflects current portfolio as of August 4, 2021 (1) Green boxes reflect companies that have executed Initial Public Offerings (IPOs) or merger transactions with Special Purpose Acquisition Companies (SPACs). XL Fleet (SPAC) and C3.ai (IPO) transactions closed in Q4 2020. ChargePoint (SPAC) and Ouster (SPAC) transactions closed in Q1 2021. STEM (SPAC) and Proterra (SPAC) transactions closed in Q2 2021. Renewable PPA Marketplace Building sustainability reporting platform Electric buses for public and private mass transit HVAC optimization for SMB and C&I EV charging network and service equipment Energy storage systems and controls Residential load disaggregation platform Battery monitoring and management software EE financing and building optimization for SMB and C&I Class 2-6 HEV and PHEV fleet electrification Residential PV and EE for low-to- middle income homeowners Commercial LIDAR and fleet safety software Unmanned aerial vehicle software control platform Artificial intelligence and enterprise data management Non-invasive energy data collection and reporting Investing in venture stage energy technology companies(1) that can provide new solutions to Exelon and its customers


 

20 Q2 2021 Earnings Release Slides 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 Q2 2021 10-Q GAAP financials, which include items listed in footnote 1 (3) Includes $258M of legacy CEG debt in 2032 As of 6/30/2021 ($M) 951 850 833 807 750 360 997 303 258 763 295 833 675 700 900 350 788 650 741 750 750 900 850 600 185 175 600 910 500 20422024 2026 1,430 1,023 2021 20482023 1,150 2025 1,650 20442022 1,200 2027 2028 2029 2047 1,250 2030 1,178 20402031 2032 2033 2034 2035 2036 2037 2038 2039 2041 1,400 2043 1,225 2045 2046 1,275 2,150 1,550 2049 2050 1,200 2051 PHI Holdco EXC Regulated ExGen(3) ExCorp Exelon Debt Maturity Profile(1,2) BGE 4.3B ComEd 9.9B PECO 4.3B PHI 7.4B ExGen recourse (3) 4.3B ExGen non-recourse 1.8B HoldCo 7.1B Consolidated 39.1B LT Debt Balances (as of 6/30/21) (1,2)


 

21 Q2 2021 Earnings Release Slides Exelon Utilities


 

22 Q2 2021 Earnings Release Slides 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 Service Commission of the District of Columbia (DCPSC) seeking an increase in electric distribution base rates • June 8, 2021, the DCPSC approved the MYP • No adjustments to reliability capital over MYP • Approved Residential/Small Commercial Assistance Programs • Established tracking PIMs focused on the District’s Climate and Clean Energy goals; working group to recommend metrics • Stay out provision requires next MYP filing after January 1, 2023 • Acceleration of tax benefits and other rate relief partially offset customer increases during MYP Test Year January 1 – December 31 Test Period 2020, 2021, 2022 Common Equity Ratio 50.68% Rate of Return ROE: 9.275%; ROR: 7.17% 2020-2022 Rate Base (Adjusted) $2.2B, $2.3B, $2.5B 2021-2022 Revenue Requirement Increase (1,2) $19.4M, $49.6M 2021-2022 Residential Total Bill % Increase (2) 1.2%, 2.8% Pepco DC Distribution Rate Case Filing 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 Apr May Jun 5/30/2019 Rebuttal testimony Filed rate case 3/6/2020 10/26/2020 - 10/30/2020Evidentiary hearings 12/9/2020Initial briefs 12/23/2020Reply briefs 4/8/2020 Commission order Intervenor testimony 6/8/2021 (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 incremental revenue requirement increases (after offsets) for the remaining 18 months of the 3-year MYP. The revenue requirement increase in 2023 will be $39.6M upon the expiration of offsets on December 31, 2022. Gross incremental revenue requirement increases (before offsets) were $41.7M and $66.9M with rates effective July 1, 2021, and January 1, 2022, respectively.


 

23 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2020-3018929 • September 30, 2020, PECO filed a general base rate filing with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in gas distribution base rates • Size of ask is driven by continued investments in gas distribution system to maintain and increase safety, reliability and customer service • June 22, 2021, the PAPUC issued its Order, approving $29.1M distribution revenue increase effective July 1, 2021 Test Year July 1, 2021 – June 30, 2022 Test Period 12 Months Budget Common Equity Ratio 53.38% Rate of Return ROE: 10.24%; ROR: 7.26% Rate Base (Adjusted) $2,426M Revenue Requirement Increase $29.1M(1) Residential Total Bill % Increase 8.3% PECO (Gas) Distribution Rate Case Filing Detailed Rate Case Schedule Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Intervenor testimony Filed rate case Rebuttal testimony 2/17/2021Evidentiary hearings Initial Briefs 1/19/2021 3/15/2021Reply Briefs 3/3/2021 12/22/2020 9/30/2020 6/22/2021Commission order(2) (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) On July 7, 2021, PECO filed a Petition for Reconsideration with the PAPUC, requesting the Commission reconsider a number of disallowances in its Order. On July 15, 2021, the PAPUC granted reconsideration, pending review and consideration of the merits of the petition. There is no required date by which the PUC must issue an order on the substance of the Petition.


 

24 Q2 2021 Earnings Release Slides 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 Public Service Commission (MDPSC) seeking an increase in electric distribution base rates • June 28, 2021, the MDPSC approved the MYP • Acceleration of tax benefits fully offset year 1 customer increase • Approved recovery of COVID-19 and Electric Vehicle regulatory assets • Smart LED Street Light program denied; however, suggested a voluntary program through EmPOWER MD or as part of the traditional infrastructure program Test Year April 1 – March 31 Test Period 2022, 2023, 2024 Common Equity Ratio 50.50% Rate of Return ROE: 9.55%; ROR: 7.21% 2022-2024 Rate Base (Adjusted) $2.1B, $2.2B, $2.3B 2022-2024 Revenue Requirement Increase (1,2) $0.0M, $36.9M, $15.3M 2022-2024 Residential Total Bill % Increase (2) 0.0%, 6.7%, 2.6% Pepco MD Distribution Rate Case Filing Detailed Rate Case Schedule Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Filed rate case 10/26/2020 4/26/2021 - 4/30/2021 Intervenor testimony Rebuttal testimony Evidentiary hearings Initial briefs Commission order Reply briefs 3/3/2021 3/31/2021 5/21/2021 6/1/2021 6/28/2021 (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 incremental revenue requirement increases (after offsets). Gross incremental revenue requirement increases (before offsets) were $20.6M, $16.3M and $15.3M with rates effective June 28, 2021, April 1, 2022, and April 1, 2023, respectively.


 

25 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. ER20120746 • December 9, 2020, ACE filed a distribution base rate case with the New Jersey Board of Public Utilities (NJBPU) to increase distribution base rates • July 14, 2021, the NJBPU approved the settlement with new rates effective on January 1, 2022 • No rate increases to customers until January 1, 2022 due to the acceleration of certain tax benefits Test Year January 1, 2020 – December 31, 2020 Test Period 12 months actual Common Equity Ratio 50.21% Rate of Return ROE: 9.60%; ROR: 6.99% Rate Base (Adjusted) $1.8B Revenue Requirement Increase $41.0M(1,2) Residential Total Bill % Increase 3.3% ACE Distribution Rate Case Filing Detailed Rate Case Schedule Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Filed rate case 7/2/2021 12/9/2020 Settlement agreement Commission order 7/14/2021 (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 annual gross incremental revenue requirement (before offsets), effective January 1, 2022. Pro-rated gross incremental revenue requirement for 2021 (July 14, 2021 through December 31, 2021) is approximately $16M and will be offset in customer rates by $16M of certain accelerated tax benefits.


 

26 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 20-0149 • March 6, 2020, Delmarva Power filed an application with the Delaware Public Service Commission (DPSC) seeking an increase in electric distribution base rates • A partial settlement agreement, primarily on customer care issues, was filed with the DPSC on February 2, 2021 • June 25, 2021, Hearing Examiner issued report recommending $5.5M increase and 9.60% ROE • July 19, 2021, parties filed exceptions to the Hearing Examiner proposal • Commission ruling expected in early August with full order to follow Test Year April 1, 2019 – March 31, 2020 Test Period 9 months actual + 3 months estimated Proposed Common Equity Ratio 50.37% Proposed Rate of Return ROE: 10.30%; ROR: 7.15% Proposed Rate Base (Adjusted) $910.2M Requested Revenue Requirement Increase $22.9M(1,2) Residential Total Bill % Increase 3.3% Delmarva DE (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Feb Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Apr May Jun Jul Aug Sep Oct Reply briefs Rebuttal testimony Q3 2021 Filed rate case 2/10/2021 - 2/15/2021 9/9/2020 Evidentiary hearings Initial briefs Intervenor testimony Commission order expected 10/26/2020 3/17/2021 3/6/2020 5/12/2021 (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.


 

27 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. R-2021-3024601 • On March 30, 2021, PECO filed a general base rate request with the Pennsylvania Public Utility Commission (PAPUC) seeking an increase in electric distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the local electric grid as well as to enable the advancement of clean technologies • In addition, the filing proposes COVID relief offerings for eligible residential and small business customers Test Year January 1, 2022 – December 31, 2022 Test Period 12 Months Budget Proposed Common Equity Ratio 53.41% Proposed Rate of Return ROE: 10.95%; ROR: 7.68% Proposed Rate Base (Adjusted) $6,386M Requested Revenue Requirement Increase $246.0M(1) Residential Total Bill % Increase 9.7% PECO (Electric) Distribution Rate Case Filing Detailed Rate Case Schedule Mar Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Initial Briefs Reply Briefs 7/22/2021 12/2021 Intervenor testimony Commission order expected Evidentiary hearings Filed rate case 6/28/2021 Rebuttal testimony 3/30/2021 9/3/2021 9/13/2021 8/11/2021 - 8/13/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings


 

28 Q2 2021 Earnings Release Slides Rate Case Filing Details Notes Docket No. 21-0367 • April 16, 2021, ComEd filed its annual distribution formula rate update with the Illinois Commerce Commission (ICC) seeking a $51.2M increase to distribution base rates • Rate increase amount is driven by continued investments in infrastructure that will enhance the reliability of the grid and enable the advancement of clean technologies and renewable energy • A final order is expected in early December Test Year January 1, 2020 – December 31, 2020 Test Period 2020 Actual Costs + 2021 Projected Plant Additions Proposed Common Equity Ratio 48.70% Proposed Rate of Return ROE: 7.36%; ROR: 5.72% Proposed Rate Base (Adjusted) $13,035M Requested Revenue Requirement Increase $45.9M(1,2) Residential Total Bill % Increase 0.2% ComEd Distribution Rate Case Filing Detailed Rate Case Schedule Apr May Jun Jul Aug Sep Oct Nov Dec Jan Feb Mar Initial briefs Reply briefs 12/2021Commission order expected 10/1/2021 Filed rate case 4/16/2021 9/13/2021Evidentiary hearings Intervenor testimony 6/30/2021 7/28/2021Rebuttal testimony 10/15/2021 (1) Revenue requirement includes changes in depreciation and amortization expense and other costs where applicable, which have no impact on pre-tax earnings (2) Revenue requirement in initial filing was an increase of $51.2M. Through the discovery period in the current proceeding, ComEd agreed to ~($5.3M) in adjustments to limit issues in the case.


 

29 Q2 2021 Earnings Release Slides Exelon Generation Disclosures June 30, 2021


 

30 Q2 2021 Earnings Release Slides Portfolio Management Strategy Protect Balance Sheet Ensure Earnings Stability Create Value Exercising Market Views % H e d g e d Purely ratable Actual hedge % Market views on timing, product allocation and regional spreads reflected in actual hedge % High End of Profit Low End of Profit % Hedged Open Generation with LT Contracts Portfolio Management & Optimization Portfolio Management Over TimeAlign Hedging & Financials Establishing Minimum Hedge Targets Credit Rating Capital & Operating Expenditure Dividend Capital Structure


 

31 Q2 2021 Earnings Release Slides Components of Gross Margin* Categories Open Gross Margin* •Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuels expense •Power Purchase Agreement (PPA) Costs and Revenues •Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada(1)) Capacity and ZEC Revenues •Expected capacity revenues for generation of electricity •Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges(2) •Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions •Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, expected generation. “Power” New Business •Retail, Wholesale planned electric sales •Portfolio Management new business •Mid marketing new business “Non Power” Executed •Retail, Wholesale executed gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency(4) •BGE Home(4) •Distributed Solar •Portfolio Management / origination fuels new business •Proprietary trading(3) Margins move from new business to MtM of hedges over the course of the year as sales are executed(5) Margins move from “Non power new business” to “Non power executed” over the course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, 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*


 

32 Q2 2021 Earnings Release Slides ExGen Disclosures (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 June 30, 2021 market conditions (5) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively (6) Reflects the midpoint of the current gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. June 30, 2021 Gross Margin Category ($M) (1) 2021 Open Gross Margin (including South, West, New England & Canada hedged GM)* (2,5) $4,250 Capacity and ZEC Revenues (2) $1,800 Mark-to-Market of Hedges (2,3) $(100) Power New Business / To Go $250 Non-Power Margins Executed $350 Non-Power New Business / To Go $150 Total Gross Margin* (Excluding Impact of February Weather Event) (4,5) $6,700 Estimated Gross Margin Impact of February Weather Event (6) $(950) Total Gross Margin* $5,750 Reference Prices (4) 2021 Henry Hub Natural Gas ($/MMBtu) $3.21 Midwest: NiHub ATC prices ($/MWh) $29.69 Mid-Atlantic: PJM-W ATC prices ($/MWh) $31.92 ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $92.86 New York: NY Zone A ($/MWh) $25.35


 

33 Q2 2021 Earnings Release Slides ExGen Disclosures (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 11 refueling outages in 2021 at Exelon-operated nuclear plants and Salem. Expected generation assumes capacity factor of 94.7% in 2021 at Exelon-operated nuclear plants, at ownership. (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) Reflects Byron and Dresden retirements in September 2021 and November 2021, respectively June 30, 2021 Generation and Hedges 2021 Expected Generation (GWh) (1) 170,800 Midwest (5) 88,200 Mid-Atlantic (2) 48,000 ERCOT 17,800 New York (2) 16,800 % of Expected Generation Hedged (3) 98%-101% Midwest (5) 99%-102% Mid-Atlantic (2) 97%-100% ERCOT 99%-102% New York (2) 97%-100% Effective Realized Energy Price ($/MWh) (4) Midwest (5) $27.00 Mid-Atlantic (2) $34.50 New York (2) $26.00


 

34 Q2 2021 Earnings Release Slides ExGen Hedged Gross Margin* Sensitivities (1) Based on June 30, 2021 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 June 30, 2021 Gross Margin* Sensitivities (with existing hedges) (1,2) 2021 Henry Hub Natural Gas ($/MMBtu) + $1/MMBtu $(80) - $1/MMBtu $65 NiHub ATC Energy Price + $5/MWh $5 - $5/MWh $(5) PJM-W ATC Energy Price + $5/MWh $(20) - $5/MWh $20 NYPP Zone A ATC Energy Price + $5/MWh $(5) - $5/MWh $5 Nuclear Capacity Factor +/- 1% +/- $15


 

35 Q2 2021 Earnings Release Slides 5,000 5,500 6,000 6,500 7,000 2021 ExGen Hedged Gross Margin* Upside/Risk A p p ro xi m a te G ro s s M a rg in * ( $ m il li o n )(1 ) (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* range is based upon an internal simulation model and are subject to change based upon market inputs, future transactions and potential modeling changes; the price distributions that generate this range are calibrated to market quotes for power, fuel, load following products, and options as of June 30, 2021. 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. $5,650 $5,800


 

36 Q2 2021 Earnings Release Slides Additional ExGen Modeling Data Total Gross Margin Reconciliation (in $M)(1) 2021 Revenue Net of Purchased Power and Fuel Expense*(2,3) $7,150 Other Revenues(4) $(175) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses $(275) Total Gross Margin* (Excluding Impact of February Weather Event) (Non-GAAP) $6,700 Estimated Gross Margin Impact of February Weather Event(5) $(950) Total Gross Margin* (Non-GAAP) $5,750 (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) Reflects the midpoint of the initial gross margin estimate of $(850)-$(1,050)M across our portfolios. Excludes bad debt and other P&L offsets. (6) ExGen O&M, TOTI and Depreciation & Amortization excludes EDF’s equity ownership share of the CENG Joint Venture (7) Other reflects Other Revenues excluding gross receipts tax revenues, includes nuclear decommissioning trust fund earnings from unregulated sites, includes the minority interest in ExGen Renewables JV, and unrealized gains or losses from equity investments (8) 2021 Adjusted O&M* includes $150M of non-cash expense related to the increase in the ARO liability due to the passage of time and a preliminary estimate of bad debt associated with the February weather event that is subject to change (9) 2021 TOTI excludes gross receipts tax of $125M Key ExGen Modeling Inputs (in $M)(1,6) 2021 Other(7) $400 Adjusted O&M*(8) $(3,700) Taxes Other Than Income (TOTI)(9) $(350) Depreciation & Amortization* $(1,000) Interest Expense $(300) Effective Tax Rate 25.0%


 

37 Q2 2021 Earnings Release Slides Appendix Reconciliation of Non-GAAP Measures


 

38 Q2 2021 Earnings Release Slides Q2 QTD GAAP EPS Reconciliation Three Months Ended June 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.20 $0.11 $0.05 $0.14 ($0.06) ($0.02) $0.41 Mark-to-market impact of economic hedging activities - - - - (0.24) - (0.24) Unrealized gains related to NDT funds - - - - (0.13) - (0.13) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.35 - 0.35 COVID-19 direct costs - - - - 0.01 - 0.01 Planned separation costs - - - - 0.01 - 0.01 Costs related to suspension of contractual offset - - - - 0.04 - 0.04 Noncontrolling interests - - - - 0.05 - 0.05 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.20 $0.11 $0.05 $0.15 $0.40 ($0.02) $0.89 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.


 

39 Q2 2021 Earnings Release Slides Q2 QTD GAAP EPS Reconciliation (continued) Three Months Ended June 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share ($0.06) $0.04 $0.04 $0.10 $0.49 ($0.07) $0.53 Mark-to-market impact of economic hedging activities - - - - (0.06) 0.01 (0.05) Unrealized gains related to NDT funds - - - - (0.31) - (0.31) Asset impairments 0.01 - - - 0.01 - 0.02 Plant retirements and divestitures - - - - 0.01 - 0.01 Cost management program - - - - 0.01 - 0.01 COVID-19 direct costs - 0.01 - - 0.02 - 0.03 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Income tax-related adjustments - - - - - 0.01 0.01 Noncontrolling interests - - - - 0.11 - 0.11 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.15 $0.05 $0.04 $0.10 $0.26 ($0.05) $0.55 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.


 

40 Q2 2021 Earnings Release Slides Q2 YTD GAAP EPS Reconciliation Six Months Ended June 30, 2021 ComEd PECO BGE PHI ExGen Other Exelon 2021 GAAP Earnings (Loss) Per Share $0.40 $0.28 $0.26 $0.27 ($0.87) ($0.22) $0.11 Mark-to-market impact of economic hedging activities - - - - (0.38) - (0.37) Unrealized gains related to NDT funds - - - - (0.09) - (0.09) Asset impairments - - - - 0.38 - 0.38 Plant retirements and divestitures - - - - 0.67 - 0.67 COVID-19 direct costs - - - - 0.01 - 0.02 Acquisition related costs - - - - 0.01 - 0.01 ERP system implementation costs - - - - - - 0.01 Planned separation costs - - - - 0.01 - 0.02 Costs related to suspension of contractual offset - - - - 0.04 - 0.04 Noncontrolling interests - - - - 0.03 - 0.03 2021 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.40 $0.28 $0.26 $0.28 ($0.18) ($0.22) $0.83 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.


 

41 Q2 2021 Earnings Release Slides Q2 YTD GAAP EPS Reconciliation (continued) Six Months Ended June 30, 2020 ComEd PECO BGE PHI ExGen Other Exelon 2020 GAAP Earnings (Loss) Per Share $0.11 $0.18 $0.22 $0.21 $0.53 ($0.13) $1.13 Mark-to-market impact of economic hedging activities - - - - (0.16) 0.01 (0.15) Unrealized losses related to NDT funds - - - - 0.18 - 0.18 Asset impairments 0.01 - - - 0.01 - 0.02 Plant retirements and divestitures - - - - 0.02 - 0.02 Cost management program - - - - 0.01 - 0.02 COVID-19 direct costs - 0.01 - - 0.02 - 0.03 Deferred Prosecution Agreement payments 0.20 - - - - - 0.20 Noncontrolling interests - - - - (0.04) - (0.04) 2020 Adjusted (non-GAAP) Operating Earnings (Loss) Per Share $0.33 $0.19 $0.23 $0.21 $0.58 ($0.12) $1.42 Note: All amounts shown are per Exelon share and represent contributions to Exelon's EPS. Amounts may not sum due to rounding.


 

42 Q2 2021 Earnings Release Slides Projected GAAP to Operating Adjustments • Exelon’s projected 2021 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 and divestitures; − Certain costs incurred to achieve cost management program savings; − Direct costs related to the novel coronavirus (COVID-19) pandemic; − Certain acquisition-related costs; − Costs related to a multi-year Enterprise Resource Program (ERP) system implementation; − Costs related to the planned separation; − Costs related to the impact of suspension of contractual offset for the Byron units; − Other items not directly related to the ongoing operations of the business; and − Generation's noncontrolling interest related to exclusion items.


 

43 Q2 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations Consolidated EU Operating TTM ROE Reconciliation ($M) Q4 2018 Q3 2018 Q2 2018 Net Income (GAAP) $1,836 $1,770 $1,724 Operating Exclusions $32 $40 $13 Adjusted Operating Earnings $1,869 $1,810 $1,737 Average Equity $19,367 $18,878 $18,467 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.6% 9.6% 9.4% Consolidated EU Operating TTM ROE Reconciliation ($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 2020 Q3 2020 Q2 2020 Q1 2020 Net Income (GAAP) 1,737 1,747 $1,728 $2,060 Operating Exclusions 246 243 $254 $31 Adjusted Operating Earnings 1,984 1,990 $1,982 $2,091 Average Equity 22,690 22,329 $21,885 $21,502 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 8.7% 8.9% 9.1% 9.7% Consolidated EU Operating TTM ROE Reconciliation ($M) Q2 2021 Q1 2021 Net Income (GAAP) $2,214 $1,841 Operating Exclusions $36 $249 Adjusted Operating Earnings $2,250 $2,090 Average Equity $23,882 $23,598 Operating (Non-GAAP) TTM ROE (Adjusted Operating Earnings/Average Equity) 9.4% 8.9% Note: Represents the twelve-month periods ending June 30, 2018-2021, March 31, 2019-2021, December 31, 2018-2020, and September 30, 2018-2020. Earned ROEs* represent weighted average across all lines of business (Electric Distribution, Gas Distribution, and Electric Transmission).


 

44 Q2 2021 Earnings Release Slides GAAP to Non-GAAP Reconciliations ExGen Adjusted O&M Reconciliation ($M)(1) 2021 GAAP O&M $4,475 Decommissioning(2) $75 Byron and Dresden Retirements(3) $475 Asset Impairments(4) ($500) Direct cost of sales incurred to generate revenues for certain Constellation and Power businesses(5) ($275) O&M for managed plants that are partially owned ($400) Other ($125) Adjusted O&M (Non-GAAP) $3,700 Note: Items may not sum due to rounding (1) All amounts rounded to the nearest $25M (2) Reflects earnings neutral O&M (3) Includes $500M of accelerated earnings neutral O&M from the retirements of Byron and Dresden (4) Reflects an impairment in the New England asset group and an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility (5) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin*