Earnings Conference Call First Quarter 2026 May 11, 2026

 
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. These forward-looking statements include, but are not limited to, statements regarding the acquisition of Calpine Corporation, the pro forma combined company and its operations, strategies and plans, enhancements to investment-grade credit profile, synergies, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow. Information adjusted for the acquisition should not be considered a forecast of future results. Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. 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 2025 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q 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. 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 adjustments for unrealized gains or losses on economic hedges, interest rate swaps, 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, and other items as set forth in the Appendix • Free cash flows before growth (FCFbG) is cash flows from operations less capital expenditures under GAAP for maintenance and nuclear fuel, equity investments, and adjusted for changes in collateral and non-recurring costs-to-achieve (CTA) • 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 unrealized gains or losses on economic hedging activities due to the volatility and unpredictability of the future changes in commodity prices – Adjusted purchased power and fuel excludes the unrealized gains or losses on 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

 
Positioned for Growth and Powering American Prosperity 5 Strong 20%+ Growth through 2029 • Base EPS* growth of 20%+ from 2026-2029 • Growth outlook excludes potential upside from: – Capturing premium value for 147 million MWhs of annual and available nuclear generation – Securing additional natural gas contracts – Accretive capital allocation • Targeting long-term rolling three-year Base EPS* growth of 10%+ Assets that Cannot be Replicated • Largest fleets of nuclear, natural gas and geothermal generation in the U.S. • Coast-to-coast fleet to support economic growth, electric system reliability and national security • New build cost of our ~55 GW fleet would be more than 3x our current enterprise value Driving Value through Capital Allocation • Strong investment grade balance sheet and growing free cash flow* enables our value-enhancing capital allocation framework: – Increase of share buyback authorization to $5.0B underscoring confidence in our outlook and executing on our future optionality – $3.9B of growth capital in projects at compelling returns – Scale that positions us to potentially bring natural gas, storage capacity and new nuclear uprates to the grid in the near term

 
Key Highlights 6 Pin Oak Creek Energy Center and Pastoria Solar Project completed Deployed ~$335M of capital for share repurchases (3) Q1 GAAP earnings of $4.49 per share (1) Q1 Adjusted Operating Earnings* of $2.74 per share (1) Affirming full-year Adjusted Operating Earnings* guidance range of $11.00 - $12.00 per share (2) Regulatory clarity will unlock data center contracting opportunities Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 30 of the Appendix (1) Q1 2026 earnings per share is based on average diluted common shares outstanding of 354 million. This reflects an average share count during the quarter, including the issuance of shares for the Calpine transaction in January. (2) Full-year 2026 earnings guidance is based on expected average diluted common shares outstanding of 361 million (3) Represents principal deployed for program before taxes Pastoria Solar Project, CCGT, and battery storage colocation PUCT approval for net metering at the Freestone Energy Center Recognized as the 2026 Most Sustainable U.S. Company by Barron’s

 
Policy Timeline and Framework Coming into Focus at PJM 7 Proposed Timeline for RBP Clarity PJM Reliability Backstop Procurement (RBP) Can Meet Capacity Demands from Large Loads Stakeholder process and final vote June 2026 Sep 2026 March 2027 May 2026 PJM files proposal at FERC Bilateral contracting begins (Phase 1) Process shifts to central procurement (Phase 2) • A market solution to solve for capacity constraints caused by large load demand • Bilateral contracting phase encourages large load customers to contract for desired products quickly • Customers can control their own cost allocation with bilateral contracting Observations from the Texas Senate Bill 6 Legislation Setting a clear policy framework enables deal making Incentivizing large loads leads to broad consumer benefits Policymaking can drive economic growth

 
Constellation has Capacity Available within PJM Framework 8 New Capacity Options Will Enable Contracting of Our Baseload Clean Generation Constellation Submitted 5,000 MWs of New Capacity to PJM (1) Includes Alphabet, Meta, Microsoft and Amazon sourced from company reports (2) Includes nuclear and geothermal generation (3) Contracted MWhs include long-term agreements and New York ZEC 48 147 195 PTC Support / Available for Long-Term Agreement Contracted (3) Expected Baseload Clean Generation in 2029 (million MWhs) (2) ~93% MWhs within PJM Nuclear Uprates Natural Gas Battery and Storage CapEx Forecasts Continue Growing from Hyperscalers (1) $410 $580 2025 ~$130 2026 Guidance $710 CapEx Actuals CapEx Guidance ($B) Q1 spend

 
Constellation has Additional Optionality to Build on Powered Land Success in ERCOT 9 • Powered land reflects shovel ready data center sites with power, permits and direct connectivity • The land is co-located with existing generation or interconnected to the grid • The site needs sufficient land contiguous to the plant and the utility's ability to approve and accommodate incremental large load within a competitive timeline Access to land adjacent to sites Additional access to grid interconnection New and existing capacity across fuel types Experience navigating policy framework Data Center at Thad Hill Energy Center 780 MWs have been signed to-date with exclusivity for an incremental 380 MWs Constellation has available sites to replicate similar transactions for a $0.20 - $0.50 EPS* impact per 1,000 MWs Additional Opportunities in Our FleetKey Considerations for Powered Land Deals

 
(1) Q1 2025 earnings per share is based on average diluted common shares outstanding of 314 million (2) Q1 2026 earnings per share is based on average diluted common shares outstanding of 354 million. This reflects an average share count during the quarter, including the issuance of shares for the Calpine transaction in January. (3) Full-year 2026 earnings guidance is based on expected average diluted common shares outstanding of 361 million Q1 2026 Results 10 Year-over-Year Adj. Operating Earnings* Drivers $0.38 $4.49 $2.14 $2.74 GAAP Net Income Q1 2025 (1) GAAP Net Income Q1 2026 (2) Adjusted Operating Earnings* Q1 2025 (1) Adjusted Operating Earnings* Q1 2026 (2) • Contribution from Calpine • Higher capacity revenue offset by higher cost to serve load during Winter Storm Fern and lower ZEC revenues • Lower O&M from stock-based compensation • Higher number of planned nuclear refueling outage days Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 30 of the Appendix $/share Affirming full-year Adjusted Operating Earnings* guidance range of $11.00 – $12.00 per share (3)

 
• Capacity factor: 92.3% – Percentage of time units were available and operating; planned and unplanned outages reduce capacity factor • Operated production of 40 TWhs • Completed two refueling outages with an average outage duration of 23 days 11 Constellation’s Coast-to-Coast Fleet Provides Reliable and Low Carbon 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) CCGT and Cogen statistics exclude Calpine assets pending divestiture (4) Equivalent Forced Outage Factor represents forced outages. Calculation adjusted to exclude events outside of management’s control. First quarter 2026 EFOF for the fleet including all gas/oil sites and hydro pumped storage was 4.5%. 75% 80% 85% 90% 95% 100% 30 35 40 45 T W h s C ap acity F acto r Q1 24 Q2 24 Q3 24 Q4 24 Q1 25 Q2 25 Q3 25 Q4 25 Q1 26 TWhs Capacity Factor Best-in-Class Nuclear Operations (1, 2) • Capacity factor: 47.1% – Percentage of time units were available and dispatched to operate based on market signals • Operated production of 23 TWhs • EFOF (4): 5.1% Strong Performance Across Our Efficient CCGT and Cogen Natural Gas Fleet (3) 30% 40% 50% 60% 70% 80% 90% 100% 15 20 25 30 35 40 45 T W h s C ap acity F acto r Q1 24 Q2 24 Q3 24 Q4 24 Q1 25 Q2 25 Q3 25 Q4 25 Q1 26 TWhs Capacity Factor

 
Leading Customer Platform Enables Businesses to Meet Their Energy and Sustainability Needs 12 Q1 2026 Retail Gas Load Served by Region (bcf)Q1 2026 Electric Load Served by Region (TWhs) 11 16 8 5 10 2 8 2 4 Midwest Mid-Atlantic ERCOT New York Other (1) 13 24 10 14 Wholesale Retail 23 38 192 19 Northeast Southeast Midwest West Note: Items may not sum due to rounding (1) Other includes New England, South and West Commercial Margins Have Expanded Over Time Expansion of traditional C&I power margins Increased demand for carbon-free solutions Incorporating the Calpine retail portfolio Retail

 
Opportunities Create Meaningful Upside to Adj. EPS* and Free Cashflow before Growth* in 2029 (1) 13 Earnings and FCFbG Opportunities in 2029Additional Optionality for 2029 Adj. EPS FCFbG Upside Earnings Upside Description Base Opportunity $125M - $325M $0.40 - $1.00 $20-$50/MWh premium to PTC floor 1 GW Nuclear PPA $75M - $175M $0.20 - $0.50 $10-$25/MWh premium for long-term agreement 1 GW Natural Gas Powered Land $25M - $75M $0.10 - $0.20 1% - 2% increased utilization driven by higher spark spreads (4) Natural Gas Capacity Factor $50M - $100M $0.10 - $0.30 $0.25 - $0.50 increase to average margins Commercial Margin $100M$0.30 PTC inflation at 3% vs 2% Increase to PTC Floor Specific to Investment $0.50 + Growth investments, share repurchases, etc. Capital Allocation (1) Opportunities may not be additive (2) Illustrative (3) Excludes after-tax proceeds from asset sales (4) Assumes 1% - 2% change in capacity factor calculated at $20 average base spark spread 30% - 35% $11.40 – $11.90 Enhanced Base 2029 2029 (2) $11.5 - $13.0B of FCFbG in 2028 - 2029 with Additional Upside 2026 – 2027 (3) 2028 - 2029 2028 – 2029 (2) $8.4B $11.5 - $13.0B FCFbG Upside Earnings Upside Description Enhanced Opportunity $150M - $450M $0.45 - $1.35 $1 - $3 power price and spark spread increase Power Prices and Spark Spreads

 
Constellation’s BBB+/Baa1 Balance Sheet is a Competitive Advantage Capital Allocation Priorities Reman Critical to Our Investment Thesis Returning Capital to Shareholders through Share Repurchases 14 Current Credit Ratings (2) (1) Constellation entered into an open-market repurchase (OMR) program in April 2026. Represents principal deployed for program before taxes. (2) Reflects senior unsecured rating for Constellation Energy Generation, LLC and Calpine LLC, respectively. Ratings shown have Stable outlook. Share Repurchase Allocation YTD (1) ~$335M Remaining Authorization Cumulatively, we have deployed ~$2.7B to repurchase ~18.5 million shares since separation $4.7B CalpineConstellation Baa1Baa1Moody’s BBB+BBB+S&P BBBN/RFitch

 
Positioned for Growth and Powering American Prosperity 15 Strong 20%+ Growth through 2029 • Base EPS* growth of 20%+ from 2026-2029 • Growth outlook excludes potential upside from: – Capturing premium value for 147 million MWhs of annual and available nuclear generation – Securing additional natural gas contracts – Accretive capital allocation • Targeting long-term rolling three-year Base EPS* growth of 10%+ Assets that Cannot be Replicated • Largest fleets of nuclear, natural gas and geothermal generation in the U.S. • Coast-to-coast fleet to support economic growth, electric system reliability and national security • New build cost of our ~55 GW fleet would be more than 3x our current enterprise value Driving Value through Capital Allocation • Strong investment grade balance sheet and growing free cash flow* enables our value-enhancing capital allocation framework: – Increase of share buyback authorization to $5.0B underscoring confidence in our outlook and executing on our future optionality – $3.9B of growth capital in projects at compelling returns – Scale that positions us to potentially bring natural gas, storage capacity and new nuclear uprates to the grid in the near term

 
Additional Disclosures 16

 
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 ) 17 PTC Provides Support for Nuclear Units When Revenues Fall Below $44.75/MWh (1) Illustrative Payoff Dynamics for Non-State-Supported Units in 2026 • The PTC provides support of up to $15.00/MWh for units when revenues are between $26.00/MWh and $44.75/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 $44.75/MWh PTC phase out, units would not receive PTC value. • When revenues fall below the $44.75/MWh phase out, the PTC will provide revenue support for the units, bringing effective realized revenues back to $44.75/MWh • Assuming revenues of $35.00/MWh, the orange line, we would expect units to receive $7.80/MWh PTC, bringing the total value the unit would receive to $42.80/MWh and $45.40/MWh (2) on a tax adjusted basis Competitive Unit Payoff $35/MWh $47/MWh PTC provides support from $26/MWh - $44.75/MWh (1) See H.R. 5376 for additional details; all numbers assume that prevailing wage requirements are satisfied (2) Grossed up assuming 25% tax rate

 
• 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 (1) 18 (1) See H.R. 537 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 (3) Reflects published inflation adjustment for 2024 of 2.482% (4) Assumes expected average shares outstanding of 361 million and effective tax rate of 26% across all years PTC Inflation AdjustmentPTC Overview Inflation Adjustment= GDP price deflator in preceeding year GDP price deflator in 2023 • The PTC is in effect through 12/31/32 • In 2025, Constellation qualified for the nuclear PTC up to $15.00/MWh; the PTC amount is reduced by 80% of gross receipts exceeding $26.00/MWh, phasing out completely after $44.75/MWh • The nuclear PTC can be credited against taxes or monetized through sale to an unrelated taxpayer Example Inflation Adjustments (2) 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 Maximum PTC Gross Receipts Threshold Power Price At Which PTC=$0 2.5% 3.0% 3.5% 2024 15.00$ 25.00$ 43.75$ 15.00$ 25.00$ 43.75$ 15.00$ 25.00$ 43.75$ 15.00$ 25.00$ 43.75$ n/a n/a n/a 2025 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ n/a n/a n/a 2026 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 15.00$ 26.00$ 44.75$ 15.00$ 27.00$ 45.75$ -$ -$ 0.20$ 2027 15.00$ 27.00$ 45.75$ 15.00$ 27.00$ 45.75$ 17.50$ 27.00$ 48.88$ 17.50$ 27.00$ 48.88$ -$ 0.80$ 0.80$ 2028 17.50$ 27.00$ 48.88$ 17.50$ 28.00$ 49.88$ 17.50$ 28.00$ 49.88$ 17.50$ 28.00$ 49.88$ 0.30$ 0.30$ 0.30$ 2029 17.50$ 28.00$ 49.88$ 17.50$ 28.00$ 49.88$ 17.50$ 29.00$ 50.88$ 17.50$ 29.00$ 50.88$ -$ 0.30$ 0.30$ 2030 17.50$ 29.00$ 49.88$ 17.50$ 29.00$ 50.88$ 17.50$ 30.00$ 51.88$ 17.50$ 30.00$ 51.88$ 0.30$ 0.60$ 0.60$ 2031 17.50$ 29.00$ 50.88$ 17.50$ 30.00$ 51.88$ 17.50$ 31.00$ 52.88$ 20.00$ 31.00$ 56.00$ 0.30$ 0.60$ 1.55$ 2032 17.50$ 29.00$ 50.88$ 17.50$ 30.00$ 51.88$ 20.00$ 32.00$ 57.00$ 20.00$ 33.00$ 58.00$ 0.30$ 1.85$ 2.15$ Impact to Base EPS* (4)2.0% Inflation Adjustment (3) 2.5% Inflation Adjustment 3.5% Inflation Adjustment3.0% Inflation Adjustment

 
19 2 0 2 7 $1,950 $334 2 0 2 8 $647 $79 2 0 2 9 2 0 3 0 $2,393 $105 2 0 3 1 2 0 3 2 2 0 3 3 $500 2 0 3 4 2 0 3 5 2 0 3 6 2 0 3 7 2 0 3 8 $900 2 0 3 9 2 0 4 0 $350 2 0 4 1 $788 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 $900 2 0 5 4 2 0 5 5 2 0 2 6 2 0 5 7 2 0 5 8 2 0 5 9 2 0 6 0 2 0 6 1 2 0 6 2 2 0 5 6 2 0 6 4 2 0 6 5 $800 2 0 6 6 $900 $600 2 0 6 3 CEG Sr. Notes CEG Tax-Exempt Bonds (3) CPN Sr. Notes (4) As of 3/31/2026 Long-Term Debt Maturity Profile (1) Long-Term Debt Balances ($B) (2) TotalCPNCEG $11.2$0.1$11.1Corporate Long-Term Debt $6.2$4.9$1.3Subsidiary Debt $17.5$5.0$12.4Total Long-Term Debt ($M) Note: Items may not sum due to rounding (1) Maturity profile excludes subsidiary debt, corporate term loans, P-cap facility, securitized debt, energy efficiency project financing, capital leases, unamortized debt issuance costs and unamortized discount/premium (2) Long-term debt balances reflect financials as of 3/31/26. Balances include instruments reflected in the maturity profile, as well as subsidiary debt and energy efficiency project financings. (3) Maturity profile reflects mandatory purchase dates for tax-exempt notes (4) Remaining “stub” balance relates to the 3.75% Calpine senior notes following the obligor exchange completed in January and is expected to remain at Calpine given the attractive coupon Corporate Long-Term Debt

 
Modeling Slides 20

 
Base Earnings Give Visibility into Constellation’s Stability and Growth 21 Enhanced Earnings (30-40% of Total) Base Earnings (60-70% of Total) Earnings that reflect additional value above base earnings Earnings that are consistent, visible and easy to calculate that will grow over time through long- term contracting, returns on contracted organic growth, PTC inflation adjustment and share repurchases • Forward power prices above base assumptions • Commercial margins above 10-year average • Capturing outsized value from volatility • Long-term contracts on generation fleet • Available nuclear generation at PTC floor (assuming 2% inflation) • Minimum expected earnings for fossil generation anchored by historical results • 10-year historical and forward weighted average commercial margins and volume

 
~20% Adjusted Operating Earnings* Growth on Base Earnings through 2029 22 $6.65 - $6.75 ~40% of Total 2026 (1) $7.60 - $7.70 35% - 40% of Total 2027 $11.40 - $11.90 30% - 35% of Total 2029 Guidance Range $11.00 - $12.00 (1) Full-year 2026 earnings guidance is based on expected average diluted common shares outstanding of 361 million. 2026 disclosures include earnings contribution from assets to be divested in 2H 2026. (2) Forward looking market prices as of 12/31/2025 2029 Projection Includes: 2029 Projection Does Not Include: • Incremental long-term deals • Higher gas plant utilization • Expanding Commercial margins • Higher return growth investments • Announced nuclear and gas long-term offtakes • Nuclear PTC at 2% inflation • Average Commercial margins • Current expectations (2) for forward looking market prices Enhanced Base

 
Opportunities Create Meaningful Upside to 2029 Adj. EPS* (1) 23 Base Earnings Opportunities in 2029Additional Optionality for 2029 Earnings ImpactDescriptionOpportunity $0.30 - $1.00 $1 - $3 power price increase for MWhs not under contract (above PTC floor) Nuclear Fleet Power Prices $0.15 - $0.35 $1 - $3 spark increase on open MWhs Gas Fleet Spark Spreads Upside to ’26-’29 Base EPS CAGR Earnings Impact DescriptionOpportunity 1% - 3%$0.40 - $1.00 $20-$50/MWh premium to PTC floor 1 GW Nuclear PPA 1% - 2%$0.20 - $0.50 $10-$25/MWh premium for long- term agreement 1 GW Natural Gas Powered Land ~1%$0.10 - $0.20 1% - 2% increased utilization driven by higher spark spreads (3) Natural Gas Capacity Factor ~1%$0.10 - $0.30 $0.25 - $0.50 increase to average margins Commercial margin 1%$0.30PTC inflation at 3% vs 2% Increase to PTC Floor (4) 2% +$0.50 + Share repurchases, growth investments, etc. Capital Allocation (1) Opportunities may not be additive (2) Illustrative (3) Assumes 1% -2% change in capacity factor calculated at $20 average base spark spread (4) Increase to PTC floor for 2029 only Enhanced Earnings Opportunities in 2029 30% - 35% $11.40 – $11.90 2029 2029 (2) Enhanced Base

 
Base Gross Margin Modeling Tool Definitions 24 DetailsBase Gross Margin • Carbon-free contracted generation for more than 5 years • Includes nuclear, solar, wind, storage and geothermal • Contracts that include energy, capacity, attributes, infrastructure and/or state program revenue Contracted Clean • CMC units • Remaining units (PTC) Available Nuclear • Contracted fossil/other generation for more than 5 years • Non-contracted fossil/other volume and spark spreads Natural Gas and Oil • Carbon-free generation contracted for less than 5 years and merchant carbon-free generation Wind/Solar/Hydro • Cleared and bilaterally sold capacity volumes with minimum expected priceNon-Nuclear Capacity • Average historical/forward 10-year unit margin and forecasted volume • Other non-commodity customer margin • Other commercial margins (~$475M/yr) Commercial Margin

 
Constellation Modeling Tools for Base Earnings 25 Note: 2026 earnings guidance based on expected average shares outstanding of 361 million. 2027 assumes average shares outstanding are held flat and is not reflective of capital allocation plans. (1) Reflected at ownership share; includes Salem and STP (2) Reflects calendar year price based on weighted average CMC price for 2024/2025, 2025/2026, and 2026/2027 planning years (3) To the extent we receive nuclear PTCs, the value will be reflected in revenues on the GAAP financial statements (4) Includes NY ZEC which reflects the total of energy, capacity, and ZEC consistent with the rate-setting mechanism (5) 2026 disclosures include earnings contribution from assets to be divested in 2H 2026 20272026 PricesQuantityPricesQuantityAdjusted Gross Margin* (Base Only) (1) Available Nuclear $34.50 /MWh23 million MWhs$34.09 /MWh53 million MWhsIllinois CMC Units (2) $45.75 /MWh127 million MWhs$44.75 /MWh101 million MWhsRemaining Units – PTC w/ 2% Inflation (3) $70.00 /MWh45 million MWhs$70.00 /MWh36 million MWhsContracted Clean (4) Natural Gas/Other Energy (5) $22 spark spread68 million MWhs$21 spark spread71 million MWhsERCOT $25 spark spread25 million MWhs$25 spark spread25 million MWhsWest $16 spark spread26 million MWhs$15 spark spread31 million MWhsOther $50.00 /MWh4 million MWhs$50.00 /MWh4 million MWhsWind/Solar/Hydro Non-Nuclear Capacity (5) $165 /MWd5,400 MWs$165 /MWd5,400 MWsWest (RA) $200 /MWd3,000 MWs$200 /MWd4,600 MWsMid-Atlantic/Midwest $85 /MWd2,500 MWs$85 /MWd2,500 MWsNew England Average MarginProjected VolumesAverage MarginProjected VolumesCommercial $4.25 - $4.35 /MWh245 million MWhs$4.25 - $4.35 /MWh245 million MWhsPower Margins $0.40 - $0.45 /dth850 million dth$0.40 - $0.45 /dth835 million dthGas Margins ~$175M~$150MNon-Commodity Customer Margin ~$475M~$475MOther Commercial Margin ($6.45 - $6.50) /MWh184 million MWhs($5.75 - $5.80) /MWh179 million MWhsNuclear Fuel Amortization $6.65 - $6.75 2026 $7.60 - $7.70 2027

 
Constellation Additional Modeling Inputs and Information 26 Note: 2026 earnings guidance based on expected average shares outstanding of 361 million. 2027 assumes average shares outstanding are held flat and is not reflective of capital allocation plans. (1) 2026 disclosures include earnings contribution from assets to be divested in 2H 2026 (2) Adjusted O&M* excludes impact from performance O&M associated with higher enhanced earnings. Total adjusted O&M* is $6,975 million and $7,075 million for 2026 and 2027, respectively. (3) TOTI excludes gross receipts tax (4) Base Interest expense excludes portion of interest attributable to re-levering following Calpine acquisition and is not reflective of capital allocation. Includes interest income from cash on hand. (5) Reflects effective tax rate including/ excluding impact of forecasted PTC revenues as of 12/31/2025. To the extent we receive nuclear PTCs, the value will be reflected in revenues on the GAAP financial statements. (6) Reflects additional O&M for compensation expense related to overperformance (7) Interest attributable to re-levering following Calpine acquisition 20272026 (1) Other Base Modeling Inputs ($7,025)($6,900)Adjusted O&M* (Excl. Performance Incentive Adj.) (2) ($675)($675)TOTI (3) --Other, Net ($2,000)($1,825)Depreciation and Amortization ($700)Base Interest Expense, Net (4) 25% / 26%26% / 26%Effective Tax Rate including / excluding PTC (5) Enhanced Modeling Tools $2,150 – $2,550$2,575 - $2,775Adjusted Gross Margin* (Enhanced Only) ($50)($75) Performance Incentive Adjustment (Applied Against Enhanced Earnings) (6) ($200)Enhanced Interest Expense, Net (7) Additional Information For Enhanced Tools as of 3/31/2026 --Power Margins Above Average 0%5%Percentage of Nuclear Fleet in PTC Zone Reference Prices as of 3/31/2026 $41.13$44.02NIHub ATC ($/MWh) $63.05$67.79PJM – W ATC ($/MWh) $61.65$65.02New York Zone A ATC ($/MWh) $21.21$18.55ERCOT – N ATC Spark Spread ($/MWh) $24.46$22.63ERCOT – N Peak Spark Spread ($/MWh)

 
Detailed Modeling Inputs for Base Earnings 27 (1) Reflects calendar year price based on weighted average CMC prices across planning years (2) Values include NY ZEC which is total of energy, capacity and ZEC consistent with rate-setting mechanism (3) Includes Salem and STP Detailed Base Earnings Modeling Inputs Available Nuclear 2026 2027 2028 2029 2030 Illinois CMC million MWhs 53 23 Illinois CMC $/MWhs (1) $34.09 $34.50 Remaining Units million MWhs 101 127 148 146 147 Remaining Units - PTC w/2% Inflation $/MWh $44.75 $45.75 $48.88 $49.88 $49.88 Contracted Clean Contracted Clean million MWhs 36 45 53 54 53 Contracted Clean $/MWhs (2) $70.00 $70.00 $77.00 $85.00 $88.00 Total Nuclear Volumes (million MWhs) 179 184 190 188 189 Number of Planned Refueling Outages (3) 15 15 13 15 14

 
Constellation Cleared/Committed Capacity Detail (1) 28 (1) Volumes are rounded and reflect Constellation’s ownership share of partially owned units (2) Revenues above the CMC value are returned to customers (3) Capacity revenue for nuclear units are included in the gross receipts calculation for the PTC and therefore should not be incorporated separately into Base Earnings calculations (4) Assets to be divested in 2026 are reflected in planning years 2025/2026 and 2026/2027 (5) Other PJM includes ~400MW committed in bilateral agreement that will be available for future capacity auctions (6) Base earnings for fossil/other capacity assumes a clearing price of $200/MWd (7) NEMA: Northeastern Massachusetts and Boston; SEMA: Southeastern Massachusetts (8) Net Qualifying Capacity excludes batteries and storage and includes ~700MW for Geysers that are included in Clean Contracted and therefore should not be incorporated separately into Base earnings calculations Volumes and prices for cleared/committed capacity differ from Base Earnings capacity assumptions and are not additive to Base Earnings PJM Volume (MW) Price ($/MWd) Volume (MW) Price ($/MWd) Volume (MW) Price ($/MWd) Nuclear ComEd (CMC units) (2) 6,200 n/a 6,200 n/a Other PJM 9,350 $270 9,350 $329 15,525 $333 Total Nuclear (3) 15,550 15,550 15,525 Fossil/Other (4) BGE 325 $466 375 $329 375 $333 Other PJM (5) 5,825 $270 6,225 $329 2,575 $333 Total Fossil/Other (6) 6,150 6,600 2,950 MISO Volume (MW) Price ($/MWd) Volume (MW) Price ($/MWd) Total Nuclear (3) 1,100 $217 1,100 $126 ISO-NE Volume (MW) Price ($/MWd) Volume (MW) Price ($/MWd) Volume (MW) Price ($/MWd) Fossil/Other NEMA/SEMA (7) 1,075 $87 1,025 $85 875 $118 NH/ME 1,150 $83 1,250 $85 1,200 $118 Total ISO-NE 2,225 2,275 2,075 CAISO Sold (MW) % Sold Sold (MW) % Sold Sold (MW) % Sold Net Qualifying Capacity (8) 5,925 95% 5,875 95% 5,275 85% 2025/2026 2026/2027 2027/2028 2026 2027 2028

 
Appendix Reconciliation of Non-GAAP Measures 29

 
Three Months Ended March 31, 20252026 Earnings Per Share Earnings Per Share Adjusted Operating Earnings* reconciliation ($M except per share data) $0.38$118$4.49$1,590 GAAP Net Income (Loss) Attributable to Common Shareholders $1.61$505($2.03)($721)Unrealized (Gain) Loss on Fair Value (1) $0.06$19($0.49)($174)Decommissioning-Related Activities (2) --$0.44$154Amortization of Acquired Commodity Contracts (3) $0.04$13$0.34$119Calpine Merger and Integration Costs (4) $0.03$11--Plant Retirements & Divestitures $0.03$9$0.06$20Pension & OPEB Non-Service (Credits) Costs --($0.04)($13)Income Tax Related Adjustments ($0.01)($2)($0.01)($3)Noncontrolling Interests (5) $2.14$673$2.74$972Adjusted Non-GAAP Operating Earnings* GAAP to Non-GAAP Reconciliation – Adjusted Operating Earnings* 30 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 354 million and 314 million for the three months ended March 31, 2026 and 2025, respectively. (1) Includes unrealized gains and losses 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 NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units (3) In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition (4) Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations (5) Represents elimination of the noncontrolling interest related to certain adjustments

 
GAAP to Non-GAAP Reconciliation – Adjusted O&M* 31 20272026Adjusted O&M* Reconciliation ($M) $7,775$7,925GAAP O&M ($275)($250)Decommissioning-Related Activities (1) ($300)($250) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (2) ($125)($400)Calpine Merger and Integration Costs (3) -($50)CCEC Settlement $7,075$6,975Adjusted 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 (3) Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations

 
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