Earnings Conference Call Second Quarter 2024 August 6, 2024

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, (the Registrants) include those factors discussed herein, as well as the items discussed in (1) the Registrants’ combined 2023 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 2024 Quarterly Report on Form 10-Q (to be filed on August 6, 2024) 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 operating earnings (and/or its per share equivalent) exclude 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 • 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 Planning (ERP) system implementation, changes in collateral, net merger and acquisitions, and equity investments and other items as set forth in the Appendix • Adjusted gross margin is defined as adjusted operating revenues less adjusted purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, variable interest entities, and net of direct cost of sales for certain end-user businesses – 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 • 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 our Adjusted Operating Earnings guidance, Projected Adjusted Gross Margin, and Projected Free Cash Flow Before Growth, we are unable to reconcile these non-GAAP financial measures to the comparable GAAP measures given the inherent uncertainty required in projecting gains and losses associated with the various fair value adjustments required by GAAP. These adjustments include future changes in fair value impacting the derivative instruments utilized in our current business operations, as well as the debt and equity securities held within our nuclear decommissioning trusts, which may have a material impact on our future GAAP results. 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 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. Non-GAAP Financial Measures Continued 4

Key Updates 5 Repurchased ~$500M of shares; bringing YTD cash deployed to $1.0B Released 2024 Constellation Sustainability Report Q2 GAAP earnings of $2.58 per share (1) Q2 Adjusted Operating Earnings* of $1.68 per share (1) Great Place To Work® Certified™ for second year in a row Raising full-year Adjusted Operating Earnings* guidance range to $7.60 - $8.40 per share (2) (1) Q2 2024 earnings per share is based on average diluted common shares outstanding of 316 million (2) Full-year 2024 earnings guidance is based on expected average diluted common shares outstanding of 315 million Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 29 of the Appendix Clinton Clean Energy Center 2025/2026 PJM Capacity Auction Results

Benefits of Co-Locating Data Centers 6 Benefits of Co-Location PJM Utilities Have Identified At Least 50 GWs of Data Center Load Growth “PSE&G has experienced an increase in new business requests and feasibility studies from potential data center customers“ - PSEG Q2 Earnings Call “We now have a total of over 17 gigawatts of interconnection requests in Pennsylvania, and new requests continue to come in each month.” - PPL Q2 Earnings Call “We are getting a fair number of load study requests from data center developers across our service area. Large load studies for this type of development have more than doubled from last year.” - FirstEnergy Q2 Earnings Call “Over 5 gigawatts in what we call engineering phase…another 13 gigawatts in what we call prospects…Beginning to see increased interest, whether they're a couple hundred to several hundred megawatts” - Exelon Q2 Earnings Call “We have commitments from customers for more than 15 gigawatts of incremental load by the end of this decade” - AEP Q2 Earnings Call  Faster timeline to power data center  Avoids unnecessary upgrade costs  Expedites economic development in states  Ensures and preserves reliability  Improves efficiency of transmission system and reduces congestion  Data centers pay for own delivery facilities  Economic certainty facilitates subsequent license renewals for nuclear plants  Increases interconnection opportunities for renewables “By utilizing the existing infrastructure of a nuclear power plant, co-location presents an unprecedented economic opportunity for local and state government, upwards of $10 billion in investment for this envisioned data center alone, without unduly shouldering costs to rate payers across PJM, and by streamlining the delays in design, planning, permitting and related regulatory hurdles, that would otherwise have potential to chill data center development in Maryland, as is the case with traditional grid connection.” UA Plumbers & Steamfitters Local 486 “Co-location of load and generation can make eminent sense because it can take advantage of pre-existing transmission infrastructure investment, and significant new load can be served without having to expend resources on expensive system upgrades.” AEP/Exelon joint answer in FERC docket no. ER24-2172

Best-in-Class Nuclear Operations (1,2) • Nuclear Capacity Factor: 95.4% • Operated production of 41.4 TWhs • Completed three refueling outages in Q2. Average refueling outage duration of completed outages in Q2 is 21 days. 7 Constellation Provides Reliable and Available Carbon-Free Power (1) Salem and STP are not included in operational metrics (outage days, capacity factor and generation) (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 C ap acity F acto r Q2 22 Q3 22 Q4 22 Q1 23 Q2 23 Q3 23 Q4 23 Q1 24 Q2 24 TWhs Capacity Factor Generated ~46.6 TWhs of carbon-free electricity, which avoided ~32.5 million metric tons of carbon dioxide; equivalent to over 7.7 million passenger vehicles being removed for one year (3) Historical Nuclear Fleet Capacity Factor (1,2) Strong Performance Across Our Renewable and Natural Gas Fleet • Renewable Energy Capture: 96.6% • Power Dispatch Match: 98.0%

Leading Customer Platform Enables Businesses to Meet Their Energy and Sustainability Needs 8 Note: Items may not sum due to rounding (1) Other includes New England, South and West (2) CORe+: Constellation’s offsite renewable product offers customers access to new-build renewable energy projects and RECs through a physical, retail electric supply agreement Q2 2024 Electric Load Served by Region (TWhs)Customer Operational Metrics (TTM) 10 11 4 4 7 6 2 4 1 Midwest Mid-Atlantic ERCOT New York Other (1) 11 17 6 11 Wholesale Retail 33% 12% 75% 90% C&I Power New Customer Win Rate C&I Gas New Customer Win Rate C&I Power Customer Renewal Rate C&I Gas Customer Renewal Rate Continue to Sign New Hourly Carbon-free Matched Electricity and CORe+ (2) Deals • Renewed existing CORe+ contract and added blended hourly-match carbon-free electricity • Added a new standalone hourly-matched carbon-free electricity contract Johns Hopkins University Applied Physics Laboratory

(1) Q2 2023 earnings per share is based on average diluted common shares outstanding of 325 million (2) Q2 2024 earnings per share is based on average diluted common shares outstanding of 316 million Q2 2024 Results 9 Year-over-Year Adj. Operating Earnings* Drivers $2.56 $2.58 $1.64 $1.68 GAAP Net Income Q2 2023 (1) GAAP Net Income Q2 2024 (2) Adjusted Operating Earnings* Q2 2023 (1) Adjusted Operating Earnings* Q2 2024 (2) • Continued strong commercial performance through portfolio optimization and better than average customer margins • Nuclear PTC with sharing of benefit under certain state programs • Higher nuclear output • Lower costs from refueling outages • Contribution from addition of ownership interest in the South Texas Project • Higher O&M • Lower revenue recognition from banked IL Zero Emission Credits (ZEC) Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 29 of the Appendix $/share

(1) Full-year 2024 earnings guidance is based on expected average diluted common shares outstanding of 315 million Raising Full-Year Adjusted Operating Earnings* Guidance Range to $7.60 - $8.40 Per Share (1) 10 • Commercial business outperforming plan in a volatile market – Strong wholesale and retail performance with load auction wins and margin expansion – Successful optimization of the portfolio to capture benefits from volatility • Partially offset by higher O&M due to impact of stock price on stock compensation and compensation expense related to commercial overperformance $/share Original Guidance Revised Guidance $8.03 $7.23 $7.63 $7.60 $8.00 $8.40

2025/2026 PJM Capacity Auction 11 2025/2026 Price ($/MW-day) Cleared Volumes (MW) (2)Zone N/A (3)6,200Nuclear – CMC Units $2703,550Nuclear – Non-CMC Units 9,750ComEd $2704,225Nuclear $2701,525Fossil/Others 5,750EMAAC $2701,575Nuclear $270100Fossil/Others 1,675MAAC $466325Fossil/Others 325BGE 15,550Nuclear 1,950Fossil/Others 17,500PJM Portfolio (4) (1) Estimate assumes forward market prices as of July 31, 2024, $270/MWd clearing prices for 2026/2027 planning year and in comparison to prior assumption of approximately $100/MWd. Actual results may vary. (2) Volumes are rounded and reflect Constellation’s ownership share of partially owned units (3) Revenues above the CMC value are returned to customers (4) Decline in cleared volumes year-over-year is related to ELCC calculation. Fossil/Others reflects the retirement of Eddystone 3 and 4. Enhanced Adjusted Operating Earnings* Uplift ($/sh) 2025 +$0.25 EPS 2026 +$1.25 EPS (1) Interactions with State Programs and PTC Capacity is included in the PTC gross receipts calculation, so the impact of higher capacity prices will depend on where updated gross receipts land around the PTC zone (and if above the floor price) The Illinois CMC contract is a comprehensive payment for energy and capacity so differences in these market prices do not impact CEG financials

Financing and Liquidity Update 12 Current Credit Ratings2024 Target Credit Metrics (1) Baa1; stable outlookMoody’s BBB+; stable outlookS&P 35% 45% Moody’s CFO Pre-WC/ Debt* S&P FFO / Debt* S&P Debt/EBITDA* < 2.0x Note: GAAP to Non-GAAP definitions for credit metrics can be found on pages 27-28 of the Appendix (1) Credit metrics forecast as of February 2024 Business and Earnings Outlook disclosure (2) Includes remaining shares delivered upon completion of the March 2024 $350M accelerated share repurchase agreement • Repurchased ~2.6 million shares (2) for ~$500 million since the Q1 2024 Earnings Call, bringing YTD cash deployed to ~$1.0 billion • Cumulatively, we have deployed ~$2.0 billion to repurchase ~16.1 million shares through August 6, 2024 • There is ~$1.0 billion remaining of the total authorized $3.0 billion share repurchase program Share Repurchase Update

Constellation – Our Assets Are Unmatched 13 Visible, Double-Digit Long-Term Base EPS Growth Backed by the Nuclear Production Tax Credit (PTC) Best and Largest Operator of Carbon-Free, Long-Lived, 24/7 Nuclear Plants Uniquely Positioned to Support Economic Growth and Electric System Reliability Growing Product Opportunities Through Leading Customer Platform 180M MWhs of Carbon-Free Electricity Will Benefit from Higher Prices and Attribute Payments Strong Free Cash Flows and High Investment Grade Balance Sheet

Additional Disclosures 14

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 ) 15 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. 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 revenue support for the units, bringing effective realized revenues back to $43.75 • 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 and $44.33/MWh (1) on a tax adjusted basis Competitive Unit Payoff $35/MWh $47/MWh PTC provides support from $25/MWh - $43.75/MWh (1) Grossed up assuming 25% tax rate

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) 16 (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 Example Assuming 2%, 3% and 4% Inflation (2)PTC Overview Inflation Adjustment= GDP price deflator in preceeding year GDP price deflator in 2023 PTC Inflation Adjustment • The PTC is in effect 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

Long-Term Debt Maturity Profile (1) 17 Note: Items may not sum due to rounding (1) Maturity profile excludes non-recourse debt, P-Cap facility, securitized debt, capital leases, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect Q2 2024 Form 10-Q GAAP financials, which include items listed in footnote 1 except for the P-Cap facility ($M) Long-Term Debt Balances (2) $7.0BRecourse $1.4BNon-Recourse $8.4BTotal Long-Term Debt As of 6/30/2024 $900 $750 $79 $600 $500 $900 $350 $788 $900 $900 $334 2 0 2 6 2 0 2 7 2 0 2 8 2 0 2 9 2 0 3 0 2 0 3 1 2 0 3 2 2 0 3 3 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 2 5 2 0 4 2 2 0 4 3 2 0 4 4 2 0 4 5 2 0 4 6 2 0 4 7 2 0 4 8 2 0 4 9 2 0 5 0 2 0 5 1 2 0 5 2 2 0 5 3 2 0 5 4 2 0 2 4 $23 2 0 4 1 Sr. Notes Tax-Exempt Bonds

• The Zero Emission Standard, passed in December 2016, requires the Illinois Power Agency (IPA) to procure contracts with zero emission facilities for 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 reference price 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 – For the first six planning years, the cost of delivered ZECs exceeded the annual compensation cap. • For the June 1, 2024 to May 31, 2025 planning year the ZEC price has been established at $9.38 per ZEC, subject to an annual cap of $222 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 reference price of $31.40/MWh ZEC Price (1) Based on the energy forward prices for each month of the applicable delivery year averaged for each trade date during the preceding calendar year18 ZEC Price ($/MWh)Planning Year $16.502017/2018 $16.502018/2019 $16.502019/2020 $16.502020/2021 $16.502021/2022 $12.012022/2023 $0.302023/2024 $9.382024/2025

Modeling Slides 19

BASE EARNINGS • Earnings that are consistent, visible, and easy to calculate that will grow over time through returns on organic growth, PTC inflation, and share repurchases • Easily modeled using simple PxQ, for example: – PTC price (assuming 2% inflation) x quantity – 13-year historical and forward average weighted commercial margin x quantity • Typically, 80-90% of expected future earnings Base Earnings Give Visibility into Constellation’s Stability and Growth Base Earnings $5.45-$5.55 2024 Adjusted Operating Earnings* Guidance Range ($7.60 - $8.40) ENHANCED EARNINGS • Earnings that reflect additional value above base earnings • Examples include: - Stronger than 13-year historical and forward average power margins - Power price sales above the PTC floor - Capturing outsized value from volatility 20 Note: Full-year 2024 earnings guidance is based on expected average diluted common shares outstanding of 315 million

2024 2025 2026 2027 2028 (1) 21 Visible 10%+ Adjusted Operating Earnings* Growth on Base Earnings Long-term growth rate of at least 10% from 2024-2028 but will vary from year to year • Inflation greater than 2% assumption • Attribute payments for reliable, carbon-free power sales • Commercial margins above the assumed 13-year average Items Not Included in Growth Rate 20282027202620252024Factors $45.75$45.75$44.75$44.75$43.75 PTC Step-Up (2% Inflation) n/a $34.50 Roll- off in May $34.09$33.47$33.04CMC Program 1215151215Number of Planned Outages (2) Typical range Above typical range Above typical range Typical rangeTypical rangeCEG Outage Duration (3) Base Earnings 181 183 180 181 184 Expected Nuclear Generation (million MWhs) (2,4) (1) Illustrative (2) Includes Salem and STP (3) Planned outage durations vary due to unit-specific attributes and outage work scope (4) Reflected at ownership share

Modeling Tools for Base Earnings 22 Note: Full-year 2024 earnings guidance is based on expected average diluted common shares outstanding of 315 million (1) To the extent we receive nuclear PTCs, the value will be reflected in revenues on the GAAP financial statements (2) Reflected at ownership share; includes Salem and STP (3) Reflects calendar year price based on weighted average CMC price for 2023/2024, 2024/2025, and 2025/2026 planning years (4) Values reflect the total of energy, capacity, and ZEC consistent with the rate-setting mechanism (5) Increase relative to Business and Earnings outlook disclosure reflects additional stock compensation due to share price increase as of June 30, 2024. This number is applied against base earnings. Total Adjusted O&M*, including performance incentive adjusted O&M, is $5,525 million. (6) TOTI excludes gross receipts tax (7) Interest expense is not reflective of capital allocation (8) Effective tax rate reflects forecasted PTC revenues as of December 31, 2023 20252024 Prices ($/MWh) Quantity (million MWhs) Prices ($/MWh) Quantity (million MWhs) Adjusted Gross Margin* (Base Only) (1) Nuclear (2) $33.4754$33.0454Illinois CMC Units (3) $60 - $6326$60 - $6125NY Units (4) $44.75102$43.75102Remaining Units (PTC) ($5.30 - $5.35)($4.85 - $4.90)Nuclear Fuel Amortization Non-Nuclear ~$60 - $70 Avg. 5~$60 - $70 Avg. 5Wind/Solar ~$452~$452Hydro ~$20 spark spread18~$20 spark spread20Natural Gas, Oil, Other See Appendix page 24See Appendix page 24Capacity Revenues Average MarginProjected VolumesAverage MarginProjected VolumesCommercial $3.50 - $3.60 / MWh205 million MWhs$3.50 - $3.60 / MWh200 million MWhsPower Margins $0.25 - $0.30 / dth840 million dth$0.25 - $0.30 / dth855 million dthGas Margins ~$450M~$400MOther Commercial Margin 20252024Other Modeling Inputs $50$75Other Revenues ($5,125)($5,400)Adjusted O&M* (5) ($450)($450)Taxes Other Than Income (TOTI) (6) ($25)($50)Other, Net ($1,025)($1,000)Depreciation and Amortization ($425)Interest Expense, Net (7) 19%17%Effective Tax Rate (8) $5.45 - $5.55 2024 $6.35 - $6.45 2025

Detailed Modeling Inputs for Base Earnings 23 Note: Items may not sum due to rounding (1) Reflected at ownership; includes Salem and STP (2) Reflects calendar year price based on weighted average CMC prices across planning years (3) Values reflect the total of energy, capacity, and ZEC consistent with the rate-setting mechanism (4) 13-Year average represents eight years of historical realized margins and five years of forward-looking forecast Expected Generation (million MWhs) (1) Nuclear 2024 2025 2026 2027 2028 IL CMC Units 54 54 53 23 - NY Units 25 26 25 26 25 Remaining Units 102 102 102 132 159 Total Nuclear 181 183 180 181 184 Number of Planned Refueling Outages (1) 15 12 15 15 12 Price ($/MWh) 2024 2025 2026 2027 2028 IL CMC Units (2) $33.04 $33.47 $34.09 $34.50 NY Units (3) $60 - $61 $60 - $63 Remaining Units (2% Inflation) $43.75 $44.75 $44.75 $45.75 $45.75 Nuclear Fuel ($4.85 - $4.90) ($5.30 - $5.35) PTC Inflation Scenarios ($/MWh) 2024 2025 2026 2027 2028 2% Inflation $43.75 $44.75 $44.75 $45.75 $45.75 3% Inflation $43.75 $44.75 $45.75 $48.88 $49.88 4% Inflation $43.75 $44.75 $45.75 $49.88 $50.88 Volume Margins (13-Year Average) (4) Commercial (Retail/Wholesale) 2024 2025 2024 Power 200 million MWhs 205 million MWhs $3.50 - $3.60/MWh Gas 855 million dth 840 million dth $0.25 - $0.30/dth

Detailed Modeling Inputs for Base Earnings (continued) 24 (1) Hydro revenue price and representative spark spread reflect consistent historical average we have achieved across hydro, natural gas, and oil assets, respectively (2) Volumes are rounded and reflect Constellation’s ownership share of partially owned units (3) ISO-NE: ISO New England; NEMA: Northeastern Massachusetts and Boston; SEMA: Southeastern Massachusetts (4) Represents offered capacity at ownership Expected Generation (million MWhs) Non-Nuclear (Energy) 2024 2025 Wind/Solar 5 5 Historical renewable contracts $60 - $70 Hydro 2 2 Hydro revenue price ($/MWh) $45 Natural Gas, Oil, Other 20 18 Representative spark spread ($/MWh) $20 2023/2024 2024/2025 2025/2026 Non-Nuclear (Capacity) Cleared Volumes (MW) (2) Price ($/MW-day) Cleared Volumes (MW) (2) Price ($/MW-day) Cleared Volumes (MW) (2) Price ($/MW-day) EMAAC - - 1,950 $55 1,525 $270 MAAC 2,175 $49 200 $49 100 $270 BGE 425 $70 425 $73 325 $466 Total PJM Portfolio 2,600 2,575 1,950 2023/2024 2024/2025 2025/2026 Capacity (4) Price ($/MW-day) Capacity (4) Price ($/MW-day) Capacity (4) Price ($/MW-day) NEMA 1,525 $66 115 $131 125 $87 SEMA 235 $597 235 $632 235 $87 Total ISO-NE (3) 1,760 350 360 Note: Capacity revenues for nuclear units are included in the gross receipts calculation for the PTC and therefore not provided Modeling Prices ($/MWh) (1)

Additional Modeling Inputs and Information 25 Note: Full-year 2024 earnings guidance is based on expected average diluted common shares outstanding of 315 million (1) Reflects additional O&M for compensation expense related to overperformance (2) Increase relative to Business and Earnings outlook disclosure reflects additional stock compensation due to share price increase as of June 30, 2024. Total Adjusted O&M*, including performance incentive adjusted O&M, is $5,525 million. (3) TOTI excludes gross receipts tax (4) Interest expense is not reflective of capital allocation (5) Reflects effective tax rate inclusive of forecasted PTC revenues as of December 31, 2023. To the extent we receive nuclear PTCs, the value will be reflected in revenues on the GAAP financial statements. (6) Reflects effective tax rate excluding impact of forecasted PTC revenues as of December 31, 2023 (7) Based on prices as of June 30, 2024 20252024Other Modeling Inputs ($M) $825-$1,100$1,125-$1,400Adjusted Gross Margin* (Enhanced Only) -($125) Performance Incentive Adjusted O&M* (Applied Against Enhanced Earnings) (1) ($5,125)($5,400)Adjusted O&M* (2) $50$75Other Revenues ($450)($450)Taxes Other Than Income (TOTI) (3) ($25)($50)Other, Net ($1,025)($975)Depreciation and Amortization ($450)Interest Expense, Net (4) 19%17%Effective Tax Rate Including PTC (5) 24%24%Effective Tax Rate Excluding PTC (6) 20252024Additional Information $0.50$1.90Power Margins Above 13-year Average 72%91%Percentage of Nuclear Fleet in PTC Zone (6/30/24) 62%96%Percentage of Nuclear Fleet in PTC Zone (7/31/24) Reference Prices (7) $38.07$30.45NIHub ATC ($/MWh) $46.89$37.77PJM-W ATC ($/MWh) $42.50$33.98New York Zone A ATC ($/MWh) $28.40$27.64ERCOT-N ATC Spark Spread ($/MWh) $41.50$37.24ERCOT-N Peak Spark Spread ($/MWh)

Appendix Reconciliation of Non-GAAP Measures 26

CFO (Pre-WC) (c) Moody’s CFO Pre-WC/Debt (3) = FFO (a) S&P FFO/Debt (2) = Adjusted Debt (d)Adjusted Debt (b) Moody’s CFO Pre-WC Calculation (3)S&P FFO Calculation (2) Cash Flow From OperationsGAAP Operating Income +/- Working Capital Adjustment+ Depreciation & Amortization - Nuclear Fuel Amortization= EBITDA +/- Other Moody’s CFO Adjustments- Interest = CFO Pre-Working Capital (c) +/- Cash Taxes + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) Moody’s Adjusted Debt Calculation (3)S&P Adjusted Debt Calculation (2) Long-Term DebtLong-Term Debt + Short-Term Debt+ Short-Term Debt + Underfunded Pension (pre-tax)+ Purchase Power Agreement and Operating Lease Imputed Debt + Operating Lease Imputed Debt+ Pension/OPEB Imputed Debt (after-tax) +/- Other Moody’s Debt Adjustments+ AR Securitization Imputed Debt = Adjusted Debt (d)- Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) GAAP to Non-GAAP Reconciliations for Credit Metrics (1) 27 (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

Adjusted Debt (a) S&P Debt/EBITDA (2) = EBITDA (b) S&P Adjusted Debt Calculation (2) Long-Term Debt + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Pension/OPEB Imputed Debt (after-tax) + AR Securitization Imputed Debt - Off-Credit Treatment of Non-Recourse Debt - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (a) S&P EBITDA Calculation (2) GAAP Operating Income + Depreciation & Amortization = EBITDA + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = EBITDA (b) GAAP to Non-GAAP Reconciliations for Credit Metrics (1) 28 (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

Three Months Ended June 30, 20242023 Earnings Per Share Earnings Per Share Adjusted Operating Earnings* Reconciliation ($M except per share data) $2.58$814$2.56$833 GAAP Net Income (Loss) Attributable to Common Shareholders ($1.28)($405)($0.99)($320)Unrealized (Gain) Loss on Fair Value (1) $0.08$26-$1Plant Retirements & Divestitures $0.11$36($0.01)($3)Decommissioning-Related Activities (2) -$1($0.03)($10)Pension & OPEB Non-Service (Credits) Costs $0.01$4$0.08$27Separation Costs (3) $0.01$2$0.02$7ERP System Implementation Costs (4) $0.17$55-$1Change in Environmental Liabilities ($0.01)($2)-($1)Noncontrolling Interests (5) $1.68$531$1.64$535Adjusted Non-GAAP Operating Earnings* GAAP to Non-GAAP Reconciliation – Adjusted Operating Earnings* 29 Note: Items may not sum due to rounding. Earnings are reflected on an after-tax basis. Earnings per share amount is based on average diluted common shares outstanding of 316 million and 325 million for the three months ended June 30, 2024 and 2023, respectively. (1) Includes mark-to-market on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments (2) Reflects all gains and losses associated with Nuclear Decommissioning Trusts (NDTs), Asset Retirement Obligation (ARO) accretion, Asset Retirement Cost (ARC) depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units (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 transition services agreement (TSA) (4) Reflects costs related to a multi-year Enterprise Resource Planning (ERP) system implemented in the first quarter of 2024 (5) Represents elimination of the noncontrolling interest related to certain adjustments

GAAP to Non-GAAP Reconciliation – Adjusted O&M* 30 20252024Adjusted O&M* Reconciliation ($M) $5,525$6,000GAAP O&M ($150)($150)Decommissioning-Related Activities (1) ($250)($225) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (2) -($75)Change in Environmental Liabilities -($25)Asset Impairment $5,125$5,525Adjusted O&M* Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M. (1) Reflects all gains and losses associated with 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 gross margin

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