Earnings Conference Call Second Quarter 2023 August 3, 2023

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. 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 Constellation Energy Corporation and Constellation Energy Generation, LLC, (Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ 2022 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, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies; (2) the Registrants’ Second Quarter 2023 Quarterly Report on Form 10-Q (to be filed on August 3, 2023) 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 13, 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. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. Cautionary Statements Regarding Forward-Looking Information 2

The Registrants report their financial results in accordance with accounting principles generally accepted in the United States (GAAP). Constellation supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted EBITDA represents earnings before interest, income taxes, depreciation and amortization, and excludes certain costs, expenses, gains and losses and other specified items, including mark-to-market adjustments from economic hedging activities and fair value adjustments related to gas imbalances and equity investments, decommissioning related activity, asset impairments, certain amounts associated with plant retirements and divestitures, pension and other post-employment benefits (OPEB) non-service credits, separation related costs and other items as set forth in the Appendix. Includes nuclear fuel amortization expense. • Adjusted cash flows from operations primarily includes net cash flows from operating activities and Collection of Deferred Purchase Price (DPP) related to the revolving accounts receivable arrangement, which is presented in cash flows from investing activities under GAAP • Free cash flows before growth (FCFbg) is adjusted cash flows from operations less capital expenditures under GAAP for maintenance and nuclear fuel, non- recurring capital expenditures related to separation and Enterprise Resource Program (ERP) system implementation, changes in collateral, net merger and acquisitions, and equity investments and other items as set forth in the Appendix • Adjusted operating revenues excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes in commodity prices • Adjusted purchased power and fuel excludes the mark-to-market impact of economic hedging activities and fair value adjustments related to gas imbalances due to the volatility and unpredictability of the future changes in commodity prices • Total gross margin is defined as adjusted operating revenues less adjusted purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, production tax credits (PTCs), variable interest entities, and net of direct cost of sales for certain end-user businesses • Adjusted operating and maintenance (O&M) excludes direct cost of sales for certain end-user businesses, Asset Retirement Obligation (ARO) accretion expense from unregulated units and decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Constellation, and other items as set forth in the reconciliation in the Appendix Due to the forward-looking nature of some projected non-GAAP financial measures, reconciliations of projected non-GAAP financial measures to the most directly comparable GAAP financial measure is not provided because we are unable to provide such reconciliation without unreasonable effort. The inability to provide each reconciliation is due to the unpredictability of the amounts and timing of events affecting the items we exclude from the non-GAAP measures. Non-GAAP Financial Measures 3

This information is intended to enhance an investor’s overall understanding of period over period financial results and provide an indication of Constellation’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 of similarly titled financial measures. Constellation 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 28 of this presentation. Non-GAAP Financial Measures Continued 4

Constellation Delivered Strong Results in the Quarter and Raises Guidance 5 Quarter Results Adjusted EBITDA* $1,031M 2023 Guidance Raised Adjusted EBITDA* $3,300M - $3,700M Prior: $2,900M - $3,300M Agreement Reached in New York to Share the Benefits of the Nuclear PTC Landmark Microsoft Hourly Carbon-Free Matching Agreement Announced Acquisition of 44% Stake in South Texas Project (STP) Constellation Sustainability Report Released Record Set in Hydrogen Blending at Hillabee

Best-in-Class Nuclear Operations (1,2) • Nuclear Capacity Factor: 92.4% • Owned and operated production of 40.1 TWhs • Completed five refueling outages (RFOs) in Q2. Average refueling outage duration of completed outages in Q2 is less than 24 days. 6 Strong Operations Deliver Reliable and Affordable Carbon-Free Power (1) Salem is not included in operational metrics (outage days, capacity factor and generation). Nuclear operations prior to Q3 2021 reflect our 50.01% ownership share of the CENG Joint Venture. Reflects 100% ownership of CENG beginning August 7, 2021. (2) Capacity factors reflect net monthly mean methodology. Capacity factors for periods in prior years may not tie to previous earnings presentations due to change in methodology for comparison purposes, however full year reported capacity factors are not impacted. (3) Carbon-free electricity reflected at ownership. Measured using the EPA Greenhouse Gas Emissions calculator https://www.epa.gov/energy/greenhouse-gas-equivalencies-calculator. 75% 80% 85% 90% 95% 100% 28 32 36 40 44 48 N u cl ea r T W h s Q1 22 C ap acity F acto r Q2 21 Q3 21 Q4 21 Q2 22 Q3 22 Q4 22 Q2 23Q1 23 TWhs Capacity Factor Generated ~42.9 TWhs of carbon-free electricity, which avoided ~30.4 million metric tons of carbon dioxide; equivalent to over 6.8 million passenger vehicles being removed for one year (3) Strong Performance Across Our Renewable and Natural Gas Fleet • Renewable Energy Capture: 96.1% • Power Dispatch Match: 99.1% Historical Nuclear Fleet Capacity Factor (1,2)

Leading Customer Platform Enables Customers to Meet Their Energy and Sustainability Needs 7 Note: Items may not sum due to rounding (1) Other includes New England, South and West Leading Customer Operational Metrics (TTM) Q2 2023 Electric Load Served by Region (TWhs) 9 11 3 4 7 2 6 2 4 Mid-AtlanticMidwest 6 Other (1)ERCOT 11 New York 17 11 Wholesale Retail 39% 16% 78% 90% Gas New Customer Win Rate Power New Customer Win Rate C&I Power Customer Renewal Rate C&I Gas Customer Renewal Rate Microsoft Hourly Carbon-Free Matching Agreement Landmark agreement combines the environmental attributes of nuclear power with hourly carbon-free energy matching to help one of Microsoft’s Virginia data centers operate on nearly 100% clean power Microsoft's data center in Boydton, Virginia will receive up to 35% in environmental attributes from nuclear power, complementing the company’s new wind and solar purchases Microsoft will track its performance using Constellation’s hourly carbon-free energy matching platform which was developed in collaboration with the company Proof that hourly, regional matching of clean energy to demand is both practical and feasible today with suitable infrastructure and energy innovation

Q2 2023 Adjusted EBITDA* Financial Results 8 Quarter Results Exceeded Expectations $603 $1,031 Q2 2023Q2 2022 ($M) • Commercial business performance – Strong wholesale and retail performance with margin expansion – Successful optimization of the portfolio to capture benefits from volatility • Illinois Zero Emission Credit (ZEC) revenue recognition

Gross Margin* Category ($M) (1) 2023 2024 2023 2024 Open Gross Margin* (including South, West, New England, Canada hedged gross margin) $4,550 $5,400 $50 ($150) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,950 $2,750 $100 - Mark-to-Market of Hedges (3) $800 $50 $350 $250 Power New Business / To Go $100 $200 ($100) ($100) Non-Power Margins Executed $350 $300 - - Non-Power New Business / To Go $50 $250 ($50) - Total Gross Margin* (4) $8,800 $8,950 $350 - Nuclear PTC Value For Plants Not Supported By State Programs (4,5) N/A $250 N/A $150 Total Gross Margin* + PTC (4,5) $8,800 $9,200 $350 $150 June 30, 2023 Change from March 31, 2023 Gross Margin* Update 9 (1) Gross margin* categories rounded to nearest $50M (2) Includes gross margin* and CMC payments for CMC plants (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on June 30 2023, market conditions (5) Plants included in PTC value are Calvert Cliffs, LaSalle, Limerick and Peach Bottom Key Messages • Gross margin increased $350M in 2023 and $150M in 2024 due to stronger new business execution • In 2023, executed $400M of Power New Business and raised Power New Business target by $300M. IL ZEC revenues increased contracted revenues by $100 million. • In 2024, executed $250M of Power New Business and raised the target by $150M, in addition the PTC provides $250M in value, mitigating the impact of falling commodity prices • PTC value reflects credits attributable to the four plants not supported by state programs and assumes gross receipts are determined using spot prices

Raising Full-Year Adjusted EBITDA* Guidance Midpoint by $400M 10 Raising full-year Adjusted EBITDA* guidance range to $3,300M - $3,700M • Commercial business outperforming plan in a volatile market – Strong wholesale and retail performance with margin expansion and load auction wins – Successful optimization of the portfolio to capture benefits from volatility – Margin shaping favorability driven by flattening of power curve • Revenue recognition of Illinois ZEC • Performance benefit from Winter Storm Elliott Revised Guidance $3,300 Original Guidance $3,700 $2,900 $3,300 ($M) $3,500 $3,100

Constellation’s Strong Balance Sheet Recognized by Moody’s Change to Positive Outlook 11 35% 45% Moody’s CFO Pre-WC/ Debt* S&P FFO / Debt* Net Debt / EBITDA* (2) 2.2x 1.8x Book Excluding Non-Recourse (1) Credit metrics forecast as of Fourth Quarter 2022 Earnings Conference Call disclosure; does not reflect planned financings for the acquisition of South Texas Project (2) 2023 forecasted year-end net debt is $6.7 billion; does not reflect planned financings for the acquisition of South Texas Project 2023E Credit Metrics (1) Current Credit Ratings Moody’s Baa2; positive outlook S&P BBB; positive outlook Share Repurchase Update Of our $1 billion share repurchase program authorized in February, we repurchased a total of ~$500 million, or ~6.2 million shares, in the first half of the year Moody’s revised outlook for Constellation to Positive from Stable

Constellation is Uniquely Positioned to Create Value for Shareholders 12 • Best-in-class nuclear operations • Largest producer of carbon-free, clean electricity • Largest provider of electricity to C&I customers • Provides hourly carbon-free energy matched to customers Unmatched, Premium Assets in the U.S. • Downside commodity price risk protected by U.S. government, while preserving ability to capture commodity price upside • Production Tax Credit grows with inflation • Supports growth opportunities that will help decarbonize the U.S. including nuclear uprates, clean hydrogen and wind repowering • Extends horizon of our clean, carbon-free nuclear fleet to 80 years Beneficiary of Inflation Reduction Act • Strong free cash flow generation allows for: – Dividend growth – Robust organic growth at compelling double-digit unlevered returns – Growth from M&A – Share repurchases Growing Value for Shareholders James A. FitzPatrick Clean Energy Center

Constellation’s ESG Principles 15 Constellation’s ESG Principles Providing Carbon-Free Energy and Climate Mitigation Commercial & Industrial Customer Transformation Innovation and Technology Enablement Carbon-Free Policy Advocacy Equity and Community Empowerment Commitment to Diversity, Equity and Inclusion Strong Corporate Governance and Risk Management Our Value Proposition and ESG Principles Constellation is positioned to deliver long-term value for our shareholders through our enduring businesses that are ready to meet the climate crisis. We are leading the transition to a carbon-free future as one of the largest providers of energy solutions to commercial and industrial (C&I) customers and the largest producer of carbon-free power in the U.S. Furthermore, our fleet is uniquely situated to be the reliable, baseline carbon- free energy source of the energy transition. We are proud of our history of actively working to reduce our emissions and improving the value, longevity and output of our assets through policy leadership, technology and innovation. Based on this foundation, Constellation is ideally suited to support our customers’ ambitions to reduce their environmental impact and seek solutions to the climate crisis. Our disciplined capital allocation strategy supports a strong investment grade balance sheet, reinvestment in our business, growth investment consistent with our corporate strategy and return of capital to owners. Our ESG principles are core to our business strategy and value proposition. Our values and ESG principles guide us in our central purpose. We are focused on driving action in these critical focus areas:

Constellation’s Climate Commitment 16 100% 100% 100% Of our owned generation will be carbon-free by 2040 Reduction of our operations- driven emissions by 2040 (1) Of C&I customers provided with specific information about how to meet GHG reduction goals Clean Energy Supply:  Clean Electricity Supply: We commit that our owned generation supply will be 100% carbon-free by 2040; with an interim goal of 95% carbon- free by 2030 subject to policy support and technology advancements.  Operational Emissions Reduction Goal: We aspire to reduce operations driven emissions by 100% by 2040 subject to technology and policy advancement  Interim target to reduce carbon emissions by 65% from 2020 levels by 2030  Constellation commits to reducing methane emissions 30% from 2020 levels by 2030, aligned with the Administration’s global methane pledge  Supply Chain Engagement: Partner with our key energy suppliers on their GHG emissions and climate adaptation strategies Clean Customer Transformation:  Prior to the end of 2022, we successfully delivered on our commitment to provide 100 percent of our C&I customers with customer-specific information on their GHG impact for facilities contracting for power and gas supply from Constellation, that include hourly carbon-free energy matching  Commit to support reductions in customers’ gas emissions and a transition to low carbon fuels Technology Enablement and Commercialization:  Commit to enable the future technologies and business models needed to drive the clean energy economy to improve the health and welfare of communities through venture investing and R&D. We will target 25 percent or more of our investments in business enterprises led by minorities, women, veteran/service-disabled veterans and LGBTQ+ individuals and will require investment recipients to disclose how they engage in equitable employment and contracting practices, using performance as a factor when considering investments (1) Any emissions that cannot be technologically reduced by that time will be offset; includes all GHGs except methane which is addressed in a separate methane reduction goal

17 Q2 2023 Adjusted EBITDA* $527 $172 ($72) Labor, Contracting and Materials Q2 2022 Market and Portfolio Conditions ($17) ZEC Revenue ($102) Nuclear Outages Capacity Revenues $603 Other Q2 2023 $1,031 ($80) ($M)

Long-Term Debt Maturity Profile (1) 18 Note: Items may not sum due to rounding (1) Maturity profile excludes non-recourse debt, P-Cap facility, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q2 2023 Form 10-Q GAAP financials, which include items listed in footnote 1 except for the P-Cap facility ($M) Long-Term Debt Balances (2) Recourse $4.7B Non-Recourse $1.6B Total Long-Term Debt $6.3B $900 $750 $79 $600 $900 $350 $788 $334 2 0 2 5 2 0 2 4 2 0 3 3 2 0 2 3 2 0 3 0 2 0 2 7 2 0 2 6 2 0 4 1 2 0 2 8 2 0 2 9 2 0 3 1 2 0 3 2 2 0 3 4 2 0 3 5 2 0 3 6 2 0 3 7 2 0 3 8 2 0 3 9 2 0 4 0 2 0 4 2 $23 Sr. Notes Tax-Exempt Bonds As of 6/30/2023

• The Zero Emission Standard, passed in December 2016, requires the Illinois Power Agency (IPA) to procure contracts with zero emission facilities for zero emission credits (ZECs) • The program has a 10-year duration that commenced with the 2017/2018 planning year and runs through May 2027 • The IPA calculates the ZEC price for each planning year based on the Social Cost of Carbon and a market price index relative to a baseline market price index – The social cost of carbon was set at $16.50/MWh for the first six years of the program and then increases at $1/MWh per year beginning in the 2023/2024 planning period – The market price index resets each year (1), while the baseline market price index was set at $31.40 • Total compensation is limited by an annual cap designed to limit the cost of ZECs to each utility’s customers – There is a “banking” mechanism, where, for ZECs delivered that exceed the annual cap each year they may be paid in subsequent years if the payments would not exceed the annual cap in the year paid – In each planning year since the program commenced on June 1, 2017, we have delivered ZECs to the utilities in excess of the annual compensation cap • For the June 1, 2023 to May 31, 2024 planning year the ZEC price has been established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap, providing available funds to compensate for ZECs delivered but not paid in prior planning years. Illinois Zero Emission Credit (ZEC) Overview Social Cost of Carbon Amount that market price index exceeds the baseline market price index of $31.40/MWh ZEC Price (1) Based on the energy forward prices for each month of the applicable delivery year averaged for each trade date during the preceding calendar year19 Planning Year ZEC Price ($/MWh) 2017/2018 $16.50 2018/2019 $16.50 2019/2020 $16.50 2020/2021 $16.50 2021/2022 $16.50 2022/2023 $12.01 2023/2024 $0.30

20 25 30 35 40 45 50 55 60 20 25 30 35 40 45 50 55 60 Market Revenues ($/MWh) M ar ke t R ev en u es + P T C ( $ / M W h ) 20 PTC Provides Support for Nuclear Units When Revenues Fall Below $43.75/MWh Illustrative Payoff Dynamics for Non-State-Supported Units in 2024 • The PTC provides support of up to $15.00/MWh for units when revenues are between $25.00/MWh and $43.75/MWh while preserving the ability of the unit to participate in upside from commodity markets • The green line assumes revenues of $47.00/MWh and since it is above the $43.75/MWh PTC phase out units would not receive PTC value • When revenues fall below the $43.75/MWh phase out, the PTC will provide support for the units • Assuming revenues of $35.00/MWh, the orange line, we would expect units to receive $7.00/MWh PTC, bringing the total value the unit would receive to $42.00/MWh Merchant Unit Payoff $35/MWh $47/MWh PTC provides support from $25/MWh - $43.75/MWh

Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 2024 15.00$ 25.00$ 43.75$ 15.00$ 25.00$ 43.75$ 15.00$ 25.00$ 43.75$ 2025 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 2026 15.00$ 26.00$ 44.75$ 15.00$ 27.00$ 45.75$ 15.00$ 27.00$ 45.75$ 2027 15.00$ 27.00$ 45.75$ 17.50$ 27.00$ 48.88$ 17.50$ 28.00$ 49.88$ 2028 15.00$ 27.00$ 45.75$ 17.50$ 28.00$ 49.88$ 17.50$ 29.00$ 50.88$ 2029 17.50$ 28.00$ 49.88$ 17.50$ 29.00$ 50.88$ 17.50$ 30.00$ 51.88$ 2030 17.50$ 28.00$ 49.88$ 17.50$ 30.00$ 51.88$ 20.00$ 32.00$ 57.00$ 2031 17.50$ 29.00$ 50.88$ 17.50$ 31.00$ 52.88$ 20.00$ 33.00$ 58.00$ 2032 17.50$ 29.00$ 50.88$ 20.00$ 32.00$ 57.00$ 20.00$ 34.00$ 59.00$ 2% Inflation 3% Inflation 4% Inflation • Starting in 2025, the maximum PTC and gross receipts threshold are subject to an inflation adjustment based on the GDP price deflator for the preceding calendar year: • Maximum PTC is rounded to nearest $2.50/MWh and gross receipts threshold is rounded to nearest $1.00/MWh Inflation of Nuclear Production Tax Credit (PTC) (1) 21 (1) See H.R. 5376 for additional details; all numbers assume that prevailing wage requirements are satisfied (2) Annual inflation adjustment is consistent with past published guidance for renewable energy credits, published annually PTC Overview Example Assuming 2%, 3% and 4% Inflation (2) Inflation Adjustment= GDP price deflator in preceeding year GDP price deflator in 2023 PTC Inflation Adjustment • The PTC is in effect beginning after 12/31/23 and through 12/31/32 • In the base year 2024, Constellation qualifies for the nuclear PTC up to $15.00/MWh; the PTC amount is reduced by 80% of gross receipts exceeding $25.00/MWh, phasing out completely after $43.75/MWh • The nuclear PTC can be credited against taxes or monetized through sale to an unrelated taxpayer

Commercial Disclosures June 30, 2023 22

Open Gross Margin* •Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuel 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)) Contracted Revenues •Expected contracted revenues from CMC payments to eligible IL plants •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 %, and 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 (3) •Constellation Home (3) “Non Power” New Business •Retail, Wholesale planned gas sales •Energy Efficiency (3) •Constellation Home (3) •Portfolio Management / origination fuels new business •Proprietary trading (4) Components of Gross Margin* Categories 23 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 these regions (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) Gross margin* for these businesses are net of direct “cost of sales” (4) Proprietary trading gross margins* will generally remain within the “Non Power” New Business category and only move to the “Non Power” Executed category upon management discretion (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*

Gross Margin Category ($M) (1) 2023 2024 2023 2024 Open Gross Margin (including South, West, New England & Canada hedged GM)* $4,550 $5,400 $50 ($150) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,950 $2,750 $100 - Mark-to-Market of Hedges (3) $800 $50 $350 $250 Power New Business / To Go $100 $200 ($100) ($100) Non-Power Margins Executed $350 $300 - - Non-Power New Business / To Go $50 $250 ($50) - Total Gross Margin* (4) $8,800 $8,950 $350 - Nuclear PTC Value for Plants Not Supported By State Programs (4,5) N/A $250 N/A $150 Total Gross Margin* + PTC (4,5) $8,800 $9,200 $350 $150 Reference Prices (4) 2023 2024 2023 2024 Henry Hub Natural Gas ($/MMBtu) $2.69 $3.52 ($0.04) ($0.11) Midwest: NiHub ATC prices ($/MWh) $28.03 $36.75 ($3.05) ($3.76) Mid-Atlantic: PJM-W ATC prices ($/MWh) $34.07 $43.95 ($2.36) ($3.38) ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $23.89 $18.06 $7.92 $2.73 New York: NY Zone A ($/MWh) $27.18 $37.38 ($0.29) $0.73 June 30, 2023 Change from March 31, 2023 Gross Margin* 24 (1) Gross margin* categories rounded to nearest $50M (2) Includes gross margin* and CMC payments for CMC plants (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on June 30, 2023, market conditions (5) Plants included in PTC value are Calvert Cliffs, LaSalle, Limerick and Peach Bottom

Generation and Hedges 2023 2024 2023 2024 Expected Generation (GWh) (1) 196,200 198,800 (600) 300 Midwest (Total) (2) 95,400 96,400 (200) - Midwest (Excluding CMCs) 40,900 42,300 (300) - Mid-Atlantic 54,800 56,100 100 (200) ERCOT 20,300 21,000 (500) 500 New York 25,700 25,300 - - % of Expected Generation Hedged (3) 96%-99% 79%-82% (1%) - 2% 1% - 4% Midwest (Total) 97%-100% 83%-86% (1%) - 2% (2%) - 1% Midwest (Excluding CMCs) 97%-100% 63%-66% 2% - 5% (2%) - 1% Mid-Atlantic 98%-101% 74%-77% (2%) - 1% 1% - 4% ERCOT 93%-96% 72%-75% 3% - 6% 8% - 11% New York 92%-95% 80%-83% 1% - 4% 9% - 12% Effective Realized Energy Price ($/MWh) (4) Midwest (Excluding CMCs) $33.50 $37.00 $1.50 ($0.50) Mid-Atlantic $49.50 $49.00 $3.00 $2.50 ERCOT (5) $11.00 $11.50 $0.50 $0.00 New York $26.50 $34.50 $1.50 ($1.00) June 30, 2023 Change from March 31, 2023 25 (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 2023 and 13 in 2024 at Constellation-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.1% and 94.2% in 2023 and 2024, respectively at Constellation-operated nuclear plants, at ownership. These estimates of expected generation in 2023 and 2024 do not represent guidance or a forecast of future results as we have not completed its planning or optimization processes for those years. (2) Midwest (Total) expected generation includes generation from CMC plants of 54,500 GWh in 2023 and 54,100 GWh in 2024 (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. It includes all hedging products, such as wholesale and retail sales of power, options and swaps. The Midwest values in the table reflect IL plants receiving CMC payments as 100% hedged. To align with the Midwest EREP, however, one should exclude plant and hedge volumes associated with CMC payments. New York values include the effect of the New York ZEC. (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 natural gas that has been purchased to lock in margin. It excludes uranium costs, RPM capacity, ZEC and CMC 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 Constellation’s energy hedges. (5) Spark spreads shown for ERCOT Generation and Hedges

Sensitivities - with existing hedges ($M) (1,2) 2023 2024 2023 2024 2024 2024 NiHub ATC Energy Price + $5.00/MWh - $60 $5 $5 ($75) ($15) - $5.00/MWh - ($60) ($5) ($5) $75 - PJM-W ATC Energy Price + $5.00/MWh - $60 $5 ($10) ($115) ($75) - $5.00/MWh - ($60) ($5) $10 $115 - NYPP Zone A ATC Energy Price + $5.00/MWh $5 $20 ($5) ($10) - - - $5.00/MWh ($5) ($20) $5 $10 - - Nuclear Capacity Factor +/- 1% +/- $30 +/- $50 ($10) ($5) - - Nuclear PTC Value For Plants Not Supported By State Programs (3) June 30, 2023 Change from March 31, 2023 June 30, 2023 Change from March 31, 2023 Gross Margin* Sensitivities 26 (1) Sensitivities rounded to the nearest $5M (2) Based on June 30, 2023, market conditions and hedged position; 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. (3) Plants included in PTC value are Calvert Cliffs, LaSalle, Limerick and Peach Bottom

Row Item Midwest (Excl. CMCs) (2) Mid-Atlantic ERCOT (3) New York (A) Start with fleet-wide open gross margin* (B) Contracted Revenues (C) Expected Generation (TWh) 42.3 56.1 21 25.3 (D) Hedge % (assuming mid-point of range) 64.5% 75.5% 73.5% 81.5% (E=C*D) Hedged Volume (TWh) 27.3 42.4 15.4 20.6 (F) Effective Realized Energy Price ($/MWh) $37.00 $49.00 $11.50 $34.50 (G) Reference Price ($/MWh) $36.75 $43.95 $18.06 $37.38 (H=F-G) Difference ($/MWh) $0.25 $5.05 ($6.56) ($2.88) (I=E*H) Mark-to-Market value of hedges ($ million) (1) $5 $215 ($100) ($60) (J=A+B+I) Hedged Gross Margin* ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin * (O) Nuclear PTC Value For Plants Not Supported By State Programs (4) (P=N+O) Total Gross Margin* + Nuclear PTC (4) $9,200 million $300 $250 $8,950 million $5.4 billion $8,200 $200 $2.75 billion $250 Illustrative Example of Modeling 2024 Total Gross Margin* 27 (1) Mark-to-market rounded to the nearest $5M (2) Uses the Midwest hedge ratio that excludes the CMC plant volume and hedges (3) Spark spreads shown for ERCOT (4) Plants included in PTC value are Calvert Cliffs, LaSalle, Limerick and Peach Bottom

Additional Constellation Modeling Data 28 Total Gross Margin* Reconciliation ($M) (1) 2023 2024 Adjusted Operating Revenues* (2) $28,075 $29,350 Adjusted Purchased Power and Fuel* (2) ($18,800) ($19,725) Nuclear PTC Value for Plants Not Supported by State Programs (3) N/A ($250) Wind PTCs ($25) ($25) Other Revenues (4) ($200) ($175) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses ($250) ($225) Total Gross Margin* (Non-GAAP) $8,800 $8,950 Nuclear PTC Value for Plants Not Supported by State Programs (3) N/A $250 Total Gross Margin* + Nuclear PTC (3) $8,800 $9,200 Note: 325 million average outstanding diluted shares as of June 30, 2023, per Form 10-Q (1) Items may not sum due to rounding. All amounts rounded to the nearest $25M (2) Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (3) Plants included in PTC value are Calvert Cliffs, LaSalle, Limerick and Peach Bottom (4) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (5) Other primarily reflects noncontrolling interest and Other Revenues (excluding gross receipts tax revenue) (6) Taxes Other Than Income (TOTI) includes gross receipts tax revenues (7) Cash tax rate excludes impact from PTC. Includes receivable from Exelon for tax credits. If receivable were to be excluded in calculation, cash tax rate would be 12% in 2023 and 26% in 2024. Inputs ($M) (1) 2023 2024 Adjusted O&M* ($4,950) ($4,850) Wind PTCs $25 $25 Other (5) $50 ($25) Taxes Other Than Income (TOTI) (6) ($425) ($450) Effective Tax Rate 25% 25% Cash Tax Rate (7) 7% 14%

Appendix Reconciliation of Non-GAAP Measures 29

S&P FFO/Debt (2) = FFO (a) Moody’s CFO Pre-WC/Debt (3) = CFO (Pre-WC) (c) Adjusted Debt (b) Adjusted Debt (d) S&P FFO Calculation (2) Moody’s CFO Pre-WC Calculation (3) GAAP Operating Income Cash Flow From Operations + Depreciation & Amortization +/- Working Capital Adjustment = EBITDA - Nuclear Fuel Amortization - Interest +/- Other Moody’s CFO Adjustments +/- Cash Taxes = CFO Pre-Working Capital (c) + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) S&P Adjusted Debt Calculation (2) Moody’s Adjusted Debt Calculation (3) Long-Term Debt Long-Term Debt + Short-Term Debt + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Underfunded Pension (pre-tax) + Pension/OPEB Imputed Debt (after-tax) +Operating Lease Imputed Debt + AR Securitization Imputed Debt +/- Other Moody’s Debt Adjustments - Off-Credit Treatment of Non-Recourse Debt = Adjusted Debt (d) - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) GAAP to Non-GAAP Reconciliations (1) 30 (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 available; therefore, management is unable to reconcile these measures (2) Calculated using S&P Methodology (3) Calculated using Moody’s Methodology

Net Debt/EBITDA = Net Debt (a) Net Debt/EBITDA Excluding Non-Recourse = Net Debt (c) Adjusted EBITDA* (b) Adjusted EBITDA* (d) Net Debt Calculation 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) Adjusted EBITDA* Calculation Adjusted EBITDA* Calculation Excluding Non-Recourse GAAP Net Income GAAP Net Income + Income Tax Expense + Income Tax Expense + Interest Expense, Net + Interest Expense, Net + Depreciation & Amortization + Depreciation & Amortization +/- Adjustments +/- Adjustments = Adjusted EBITDA* (b) - EBITDA from Projects Financed by Non-Recourse Debt = Adjusted EBITDA* Excluding Non-Recourse Debt (d) GAAP to Non-GAAP Reconciliations (1) 31 (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

Three Months Ended June 30, Six Months Ended June 30, Adjusted EBITDA* Reconciliation ($M) 2022 2023 2022 2023 GAAP Net (Loss) Income ($111) $833 ($5) $929 Income Taxes (1) ($270) $342 ($323) $472 Depreciation and Amortization $277 $274 $557 $542 Interest Expense, Net $56 $103 $112 $210 Unrealized (Gain) Loss on Fair Value (2) ($24) ($426) $94 ($129) Plant Retirements & Divestitures ($8) - ($8) ($27) Decommissioning-Related Activities (3) $684 ($116) $1,038 ($356) Pension & OPEB Non-Service Credits ($33) ($14) ($58) ($27) Separation Costs (4) $31 $36 $68 $66 ERP System Implementation Costs (5) $5 $10 $11 $15 Change in Environmental Liabilities $8 $1 $8 $17 Noncontrolling Interests (6) ($12) ($12) ($25) ($24) Adjusted EBITDA* $603 $1,031 $1,469 $1,688 GAAP to Non-GAAP Reconciliation 32 Note: Items may not sum due to rounding (1) In 2022, includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net (2) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments (3) Reflects all gains and losses associated with Nuclear Decommissioning Trusts (NDT), Asset Retirement Obligation (ARO) accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (4) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the Transition Services Agreement (TSA) (5) Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation (6) Represents elimination of the noncontrolling interest related to certain adjustments

GAAP to Non-GAAP Reconciliation 33 Adjusted O&M* Reconciliation ($M) 2023 2024 GAAP O&M $5,525 $5,275 Decommissioning (1) ($175) ($200) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (2) ($250) ($225) Separation Costs (3) ($100) - ERP System Implementation (4) ($25) - Change in Environmental Liabilities ($25) - Adjusted O&M* (Non-GAAP) $4,950 $4,850 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M. (1) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (2) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* (3) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (4) Reflects costs related to a multi-year ERP system implementation

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