EX-99.2 3 ceg-20250506992.htm EX-99.2
Earnings Conference Call First Quarter 2025 May 6, 2025

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 proposed transaction between Constellation and Calpine Corporation, the expected closing of the proposed transaction and the timing thereof. This includes statements regarding the financing of the proposed transaction and 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 proposed transaction 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 2024 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 18, Commitments and Contingencies; (2) the Registrants’ First Quarter 2025 Quarterly Report on Form 10-Q (to be filed on May 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, 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 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 Messages 5 Crane Clean Energy Center Solid financial performance: Q1 GAAP earnings of $0.38 per share (1) Q1 Adjusted Operating Earnings* of $2.14 per share (1) Nearing long-term agreements with customers to sell our clean, reliable and available MWs Cost of new build generation substantially higher Deals can get done without clarity from FERC, but clarity is coming Multiple ways to serve our customers in on-grid, co-located, and behind-the-meter configurations (1) Q1 2025 earnings per share is based on average diluted common shares outstanding of 314 million Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 31 of the Appendix

The Data Economy Is Coming 6 Trump Administration Recognizes National Security Imperative of AI Hyperscalers Reaffirm CapEx Plans • Amazon – “We continue to believe AI is a once-in-a-lifetime reinvention of everything we know, the demand is unlike anything we’ve seen before, and our customers, shareholders, and business will be well-served by our investing aggressively now.” – CEO Andy Jassy Apr 10, 2025 • Google – “For the full year 2025, we still expect to invest approximately $75 billion in CapEx this year.” – Q1 2025 Earnings Call Apr 24, 2025 • Meta – “We anticipate our full year 2025 capital expenditures, including principal payments on finance leases, will be in the range of $64-72 billion, increased from our prior outlook of $60-65 billion. This updated outlook reflects additional data center investments to support our artificial intelligence efforts as well as an increase in the expected cost of infrastructure hardware.” – Q1 2025 Earnings Call Apr 30, 2025 • Microsoft – “We remain committed to investing against the strong demand signals we see for our services. So, as a reminder, our earlier comments on FY 2026 capital expenditures remain unchanged. We expect CapEx to grow.” – Q3 2025 Earnings Call Apr 30, 2025 “The global race for AI dominance is the next Manhattan project … the United States can and will win” Chris Wright (Energy Secretary) Apr 3, 2025 “Need the build out of big AI data centers…and to get power generated for them” David Sacks (AI & Crypto Czar) Jan 28, 2025 “It is the policy of the United States to sustain and enhance America’s global AI dominance in order to promote human flourishing, economic competitiveness, and national security” Trump Presidential Action (Jan 23, 2025)

Data Centers Pursuing Multiple Jurisdictions for the Same Project 7 89 111 73 73 39 41 10 0 20 40 60 80 100 120 140 GWs ISO Large Load Demand Forecast BCG McKinsey S&P BNEF 140 Sources: MISO, PJM, ERCOT, BCG, McKinsey, S&P and BNEF; adjusted for capacity factor MISO PJM ERCOT PJM, ERCOT and MISO serve ~46% of US power demand, but project large load demand double the average of third-party estimates for total US data center demand by 2030 Third-party Forecasts for US Data Center Demand by 2030

$0 $20 $40 $60 $80 $100 $120 $140 $160 $180 $/MWh up to $6 Natural Gas (2) up to $50 Hybrid: Solar + 4hr Storage (3) 2026 2027 2028 2029 $65 Billion – The Cost of Calpine’s Gas Units at Today’s New Build Cost 8 Current Market Forwards do not Support New Build Economics (1) (1) PJM W and NIHub ATC Forwards as of 3/31/2025 plus capacity using midpoint of $175 / $325 floor & cap; ERCOT ATC Forwards as of 3/31/2025 (2) LCOE for Natural Gas based on a $2,500 /kW cost for CCGT online in 2030. Tariff impact assumes up to a 25% tariff on 50% of project cost. (3) LCOE for Hybrid: Solar + 4hr storage based on regional average cost est. of $2,500 / kW placed online in 2030. Tariff impact assumes up to a 50% tariff on 70% of project costs. Cost of New Build Tariffs PJM W Forwards NIHub Forwards ERCOT Forwards $88 $122 Cost and Lead Time For Critical Equipment Continues to Grow • “Currently, an electric utility or generation developer that orders a transformer may have to wait 2 to 4 years for it to be delivered, compared to a wait of just months as recently as 2020” – National Infrastructure Advisory Council • “Transformer lead times have been increasing for the last 2 years – from around 50 weeks in 2021, to 120 weeks on average in 2024. Large transformers, both substation power and generator step-up transformers, have lead times ranging from 80 to 210 weeks.” – Wood Mackenzie • “I would expect by the end of the summer, we will be largely sold out through the end of ‘28 with this equipment” – GE Vernova CEO, Scott Strazik (CERA 2025)

Curtailing Peak Load for Less Than 50 Hours Would Enable ~100 GWs of New Load to Come Onto the System 9 Source: Nicholas Institute for Energy and Environment & Sustainability: Rethinking Load Growth. nicholasinstitute.duke.edu/sites/default/files/publications/rethinking-load-growth.pdf. 98% of the time about 10% of power plants are not running 95% of the time about 20% of power plants are not running 80% of the time about 1/3 of the nation’s power plants are not running

Existing MWs to meet customer needs, supported by best-in-class operations Aligns with customer desire for reliable, clean power with price certainty for decades Acquired land around sites and procuring long- lead time equipment to ensure speed to connection Nuclear uprate opportunities plus license extensions bring and maintain clean, firm MWs for the grid Future geographic footprint and technology mix offer national solutions for large customers Investment grade balance sheet provides customers certainty that we can meet our commitments Constellation is Well-Positioned to Capture Value from the Data Economy 10 Limerick Clean Energy Center

Calpine Transaction Remains On Track to Close by Year-end 11 On Track to Receive Regulatory Approval The Acquisition of Calpine Better Positions Constellation for the Future D O J FE R C S ta te a n d O th er • Filed with DOJ on January 14th • Received second request on April 11th • Filed with FERC on January 24th • Received deficiency letter on March 27th • Filed response to deficiency letter on April 28th • Other state and federal regulatory filings were submitted by February 7th Creates leading coast-to-coast generation fleet that is irreplaceable, dispatchable, reliable, and the cleanest in America (1) Reliable, clean and sustainable MWs are a premium product Adj. Operating Earnings per Share* accretive by more than 20% in 2026 and at least $2.00 per share through 2029, adding more than $2B in free cash flow before growth* annually Opportunity to provide energy and sustainability solutions to more customers Brings together two exceptional teams Strong investment grade balance sheet better positions us to serve customers and offers strategic flexibility Potential to add at least 3,500 MWs of reliable power resources to the grid including 1,900 MWs already announced Continued optionality from selling attributes of clean, reliable nuclear fleet while broadening the resource options for our customers (1) Note: Constellation and Calpine together will have the lowest carbon intensity of America’s ten largest generation owners. Reflects 2022 regulated and non-regulated investor-owned generators. Source: Benchmarking Air Emissions, November 2024.

(1) Q1 2024 earnings per share is based on average diluted common shares outstanding of 318 million (2) Q1 2025 earnings per share is based on average diluted common shares outstanding of 314 million (3) Full-year 2025 earnings guidance is based on expected average diluted common shares outstanding of 311 million Q1 2025 Results 12 Year-over-Year Adj. Operating Earnings* Drivers $2.78 $0.38 $1.82 $2.14 GAAP Net Income Q1 2024 (1) GAAP Net Income Q1 2025 (2) Adjusted Operating Earnings* Q1 2024 (1) Adjusted Operating Earnings* Q1 2025 (2) • Continued strong commercial performance through portfolio optimization, serving more customer demand and lower cost to serve • Higher ZEC and CMC prices • Fewer Nuclear PTCs net of state programs due to market conditions Note: GAAP to Non-GAAP reconciliations for Adjusted Operating Earnings* can be found on page 31 of the Appendix $/share Reaffirming full-year Adjusted Operating Earnings* guidance range of $8.90 – $9.60 per share (3)

Best-in-Class Nuclear Operations (1,2) • More than 1,150 MWs including Crane Clean Energy Center and uprates, selected for fast-track interconnection • Nuclear capacity factor: 94.1% • Operated production of 41 TWhs • Completed three refueling outages with an average outage duration of 24 days 13 Constellation Provides Reliable and Available Emissions-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) Emissions-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 Q1 23 Q2 23 Q3 23 Q4 23 Q1 24 Q2 24 Q3 24 Q4 24 Q1 25 TWhs Capacity Factor Generated ~46.8 TWhs of emissions-free electricity, which avoided ~31.4 million metric tons of carbon dioxide; equivalent to over 7.3 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: 96.2% • Power Dispatch Match: 99.2%

Leading Customer Platform Enables Businesses to Meet Their Energy and Sustainability Needs 14 Note: Items may not sum due to rounding (1) Other includes New England, South and West Q1 2025 Electric Load Served by Region (TWhs)Customer Operational Metrics (TTM) 10 11 4 4 7 2 7 2 5 Midwest Mid-Atlantic ERCOT New York Other (1) 11 19 5 12 Wholesale Retail 30% 10% 80% 88% 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

Unprecedented Demand Growth Still Expected Despite Recession Concerns 15 U.S. Annual Electricity Sales (1) Global Data Center Demand is Both from AI and Non-AI (2) Note: Items may not sum due to rounding (1) Energy Information Administration (EIA) (2) McKinsey: The cost of compute – a $7 trillion dollar race to scale data centers (April 2025) Residential Commercial Industrial 600 700 800 900 1,000 1,100 1,200 1,300 1,400 1,500 1,600 1,700 2000 2005 2010 2015 2020 2025 Million MWHs 44 62 83 102 124 156 38 40 45 50 56 64 2025 2026 2027 2028 2029 2030 82 103 128 153 181 219 Non-AI Workload AI Workload GWs Periods of Recession

Higher Inflation Adjustment Results in Higher Nuclear PTC Floor Price 16 $40 $45 $50 $55 2024 2025 2026 2027 2028 2029 2030 M ar ke t R ev en u es + P T C ($ /M W h ) 2% 2024: 2.3 - 2.6%, 2025 - 2030: 2% 3% 4% PTC was not in place during previous economic or power market downturns PTC floor value grows at faster rate than forecasted expenses Estimated 2025 inflation adjustment between 2.3% and 2.6% yields ~$500M in incremental revenue in 2028 on base earnings ~$500M in 2028 incremental base revenue when 2025 inflation adjustment falls between 2.3% and 2.6% (1) (1) Reflects 158 million MWh of expected non-NY nuclear generation (excluding Crane) multiplied by the difference in PTC floor prices under prior and current forecast scenarios

Constellation – Our Assets Are Unmatched Today and Tomorrow 17 Visible, Double-Digit Long-Term Base EPS Growth Backed by Nuclear PTC, Contracts and Customer Margins Best and Leading Operator of Clean, Emissions-free and Low-emissions, Reliable Generation, with Coast-to-Coast Presence Uniquely Positioned to Support Economic Growth, Electric System Reliability and National Security Growing Product Opportunities Through Leading Customer Platform Significant Opportunities to Sell Clean Attributes, Participate in Data Economy, and Grow Clean, Reliable MWs Strong Free Cash Flows and High Investment Grade Balance Sheet

Additional Disclosures 18

19 Complementary Capabilities Will Create Value for Combined Company A ss et s C u st o m er P ro d u ct s Largest Nuclear Fleet Leading Natural Gas Fleet Largest Geothermal Fleet Battery Storage Renewables Hourly CFE, CORE/CORe+, EFECs Customized Blending of Products Cross Selling Power and Gas Combined M ar ke ts PJM ERCOT California New England Strong Management Team Best Operator of Nuclear Plants Leading Operator of Natural Gas Best Customer Platform Strong Development Capabilities P eo p le B al an ce S h ee t/ C as h F lo w Strong Investment Grade Ratings Strong Cash Flow for Allocation O p p o rt u n it ie s fo r G ro w th Benefits from Data Economy for Nuclear Benefits from Data Economy for Natural Gas New Nuclear MWs Carbon Capture and Sequestration Solar and Battery Storage Combined

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 $44.75/MWh (1,2) Illustrative Payoff Dynamics for Non-State-Supported Units in 2025 (2) • 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 • 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 (3) 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) Annual inflation adjustment is consistent with past published guidance for renewable energy credits, published annually. Actual inflation adjustment for the preceding calendar is not yet available; guidance for 2025 is expected in the second or third quarter of 2025. (3) 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 Adjustment 3% Inflation Adjustment 4% Inflation Adjustment • 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) 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. Actual inflation adjustment for the preceding calendar is not yet available; guidance for 2025 is expected in the second or third quarter of 2025. Example Assuming 2%, 3% and 4% Inflation Adjustment (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 2025, Constellation qualifies 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

Our Investment Grade Balance Sheet is a Competitive Advantage 22 Baa1; stable outlookMoody’s BBB+; stable outlookS&P Note: Items may not sum due to rounding (1) On January 10, 2025, Moody’s and S&P affirmed ratings at Baa1 and BBB+, respectively, with stable outlook following the announced acquisition of Calpine (2) Maturity profile excludes non-recourse debt, P-Cap facility, securitized debt, energy efficiency project financing, capital leases, unamortized debt issuance costs and unamortized discount/premium (3) Long-term debt balances reflect Q1 2025 Form 10-Q GAAP financials, which include items listed in footnote 2 except for the P-Cap facility Long-Term Debt Maturity Profile (2) Long-Term Debt Balances (3) $7.0BRecourse $1.4BNon-Recourse $8.4BTotal Long-Term Debt As of 3/31/2025 ($M) $ 9 0 0 $ 75 0 $ 6 0 0 $ 5 0 0 $ 9 0 0 $ 3 5 0 $ 78 8 $ 9 0 0 $ 9 0 0 $ 3 3 4 2 0 2 5 2 0 2 6 2 0 2 7 2 0 2 8 $ 79 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 4 1 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 Sr. Notes Tax-Exempt Bonds Current Credit Ratings (1)

Modeling Slides 23

BASE EARNINGS • Earnings that are consistent, visible, and easy to calculate that will grow over time through returns on organic growth, PTC inflation adjustment, and share repurchases • Easily modeled using simple PxQ, for example: – PTC price (assuming 2% inflation adjustment) x quantity – 10-year historical and forward average weighted commercial margin x quantity • Typically, 65-75% of expected future earnings Base Earnings Give Visibility into Constellation’s Stability and Growth ENHANCED EARNINGS • Earnings that reflect additional value above base earnings • Examples include: - Stronger than 10-year historical and forward average power margins - Power price sales above the PTC floor - Capturing outsized value from volatility 24 Adjusted Operating Earnings* Guidance Range $8.90 - $9.60 Note: Full-year 2025 earnings guidance is based on expected average diluted common shares outstanding of 311 million Base Earnings $6.70 - $6.80

2025 2026 2030 (1) 20292028202720262025Factors $49.88$45.75$45.75$44.75$44.75PTC Step-Up (2% Inflation Adjustment) n/an/a $34.50 Roll-off in May $34.09$33.47CMC Program 1612151512Number of Planned Refueling Outages (2) Above typical range Typical range Above typical range Above typical range Typical rangeCEG Outage Duration (3) 188187180180182 Expected Nuclear Generation (million MWh) (2,4) 25 Standalone Constellation Visible 13%+ Adjusted Operating Earnings* Growth on Base Earnings Through 2030 Long-term Growth Rate of at Least 13% from 2024-2030 but Will Vary from Year to Year • Inflation adjustment greater than 2% assumption • Attribute payments for reliable, emissions-free power sales • Commercial margins above the assumed 10-year average Items Not Included in Growth Rate Base Earnings 182 180 180 187 188 Expected Nuclear Generation (million MWhs) (2,4) (1) Illustrative (2) Includes Salem and STP at ownership share. Includes impact from Crane beginning 2028. (3) Planned outage durations vary due to unit-specific attributes and outage work scope (4) Reflected at ownership share

Standalone Constellation Modeling Tools for Base Earnings 26 Note: 2025 earnings guidance based on expected average shares outstanding of 311 million. 2026 assumes average shares outstanding are held flat. (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 2024/2025, 2025/2026, and 2026/2027 planning years (4) Values reflect the total of energy, capacity, and ZEC consistent with the rate-setting mechanism (5) Adjusted O&M* excludes impact from performance O&M associated with higher enhanced earnings. Total Adjusted O&M* is $5,375 million and $5,450 million for 2025 and 2026, respectively. (6) TOTI excludes gross receipts tax (7) Interest expense is not reflective of capital allocation. Includes interest income from cash on hand. (8) Effective tax rate reflects PTC revenues as of 12/31/2024 20262025 Prices ($/MWh) Quantity (million MWhs) Prices ($/MWh) Quantity (million MWhs) Gross Margin* (Base Only) (1) Nuclear (2) $34.0953$33.4755Illinois CMC Units (3) $61 - $6325$61 - $6226NY Units (4) $44.75102$44.75101Remaining Units (PTC) ($5.75 - $5.80)($5.30 - $5.35)Nuclear Fuel Amortization Non-Nuclear ~$60 - $70 Avg. 5~$60 - $70 Avg. 5Wind/Solar ~$30M~$30MWind PTC ~$452~$452Hydro ~$20 spark spread18~$20 spark spread20Natural Gas, Oil, Other See Appendix page 28See Appendix page 28Capacity Revenues Average MarginProjected VolumesAverage MarginProjected VolumesCommercial $3.70 - $3.80 / MWh200 million MWhs$3.70 - $3.80 / MWh205 million MWhsPower Margins $0.25 - $0.30 / dth865 million dth$0.25 - $0.30 / dth845 million dthGas Margins ~$675M~$600MOther Commercial Margin 20262025Other Modeling Inputs $25$25Other Revenues ($5,400)($5,225)Adjusted O&M* (Excl. Performance Incentive Adj.) (5) ($475)($450)TOTI (6) $25$25Other, Net ($925)($925)Depreciation and Amortization ($325)Interest Expense, Net (7) 25%24%Effective Tax Rate (8) $6.70 - $6.80 2025 $5.95 - $6.05 2026

Standalone Constellation Detailed Modeling Inputs for Base Earnings 27 (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) 10-Year average represents five years of historical realized margins and five years of forward-looking forecast Expected Generation (million MWhs) (1) Nuclear 2025 2026 2027 2028 2029 IL CMC Units 55 53 23 - - NY Units 26 25 26 25 26 Remaining Units 101 102 132 158 157 Crane - - - 3 6 Total Nuclear 182 180 180 187 188 Number of Planned Refueling Outages (1) 12 15 15 12 16 Price ($/MWh) 2025 2026 2027 2028 2029 IL CMC Units (2) $33.47 $34.09 $34.50 NY Units (3) $61 - $62 $61 - $63 Remaining Units (PTC - 2% Inflation) $44.75 $44.75 $45.75 $45.75 $49.88 Nuclear Fuel ($5.30 - $5.35) ($5.75 - $5.80) PTC Inflation Scenarios ($/MWh) 2025 2026 2027 2028 2029 2% Inflation $44.75 $44.75 $45.75 $45.75 $49.88 3% Inflation $44.75 $45.75 $48.88 $49.88 $50.88 4% Inflation $44.75 $45.75 $49.88 $50.88 $51.88 Volume Margins (10-Year Average) (4) Commercial (Retail/Wholesale) 2025 2026 2025 Power 205 million MWhs 200 million MWhs $3.70 - $3.80/MWh Gas 845 million dth 865 million dth $0.25 - $0.30/dth

Standalone Constellation Detailed Modeling Inputs for Base Earnings (continued) 28 (1) Hydro revenue price and representative spark spread reflect consistent historical average we have achieved across hydro and fossil 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) 2025 2026 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) $20 2024/2025 2025/2026 Non-Nuclear (Capacity) Cleared Volumes (MW) (2) Cleared Prices ($/MW-day) Cleared Volumes (MW) (2) Cleared Price ($/MW-day) EMAAC 1,950 $55 1,525 $270 MAAC 200 $49 100 $270 BGE 425 $73 325 $466 Total PJM Portfolio 2,575 1,950 2024/2025 2025/2026 Capacity (4) Price ($/MW-day) Capacity (4) Price ($/MW-day) NEMA 115 $131 125 $87 SEMA 235 $632 235 $87 Total ISO-NE (3) 350 360 Modeling Prices ($/MWh) (1) Note: Base earnings assumes clearing price of $150/MW-d. Capacity revenues for nuclear units are included in the gross receipts calculation for the PTC and therefore not provided

Standalone Constellation Additional Modeling Inputs and Information 29 Note: Full-year 2025 earnings guidance is based on expected average diluted common shares outstanding of 311 million. 2026 assumes average shares outstanding are held flat. (1) Reflects additional O&M for compensation expense related to overperformance (2) Excludes impact from performance O&M associated with higher enhanced earnings. Total Adjusted O&M* is $5,375 million and $5,450 million for 2025 and 2026, respectively. (3) TOTI excludes gross receipts tax (4) Interest expense, net is not reflective of capital allocation. Includes interest income from cash on hand. (5) Reflects effective tax rate inclusive of forecasted PTC revenues as of 12/31/2024. To the extent we receive nuclear PTCs, the value will be reflected in revenues on the GAAP financial statements. (6) Reflects effective tax rate excluding impact of forecasted PTC revenues as of 12/31/2024 (7) Based on prices as of 3/31/2025 20262025Other Modeling Inputs ($M) $1,175 - $1,550$1,050 - $1,300Adjusted Gross Margin* (Enhanced Only) ($50)($150) Performance Incentive Adjustment (Applied Against Enhanced Earnings) (1) ($5,400)($5,225) Adjusted O&M* (Excl. Performance Incentive Adj.) (2) $25$25Other Revenues ($475)($450)Taxes Other Than Income (TOTI) (3) $25$25Other, Net ($925)($925)Depreciation and Amortization ($325)Interest Expense, Net (4) 25%24%Effective Tax Rate Including PTC (5) 25%25%Effective Tax Rate Excluding PTC (6) 20262025Additional Information -$0.35Power Margins Above 10-year Average 0%0%Percentage of Nuclear Fleet in PTC Zone (3/31/25) Reference Prices (7) $42.43 $39.95 NIHub ATC ($/MWh) $56.37 $54.00 PJM-W ATC ($/MWh) $51.96 $54.35 New York Zone A ATC ($/MWh) $24.63 $21.78 ERCOT-N ATC Spark Spread ($/MWh) $32.77$31.10ERCOT-N Peak Spark Spread ($/MWh)

Appendix Reconciliation of Non-GAAP Measures 30

Three Months Ended March 31, 20252024 Earnings Per Share Earnings Per Share Adjusted Operating Earnings* Reconciliation ($M except per share data) $0.38$118$2.78$883 GAAP Net Income (Loss) Attributable to Common Shareholders $1.61$505($0.53)($170)Unrealized (Gain) Loss on Fair Value (1) $0.03$11$0.04$12Plant Retirements & Divestitures $0.06$19($0.21)($67)Decommissioning-Related Activities (2) $0.03$9$0.01$2Pension & OPEB Non-Service (Credits) Costs --$0.02$5Separation Costs --$0.01$4ERP System Implementation Costs $0.04$13--Acquisition Related Costs (3) --($0.28)($88)Income Tax Related Adjustments (4) ($0.01)($2)($0.01)($2)Noncontrolling Interests (5) $2.14$673$1.82$579Adjusted Non-GAAP Operating Earnings* GAAP to Non-GAAP Reconciliation – Adjusted Operating Earnings* 31 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 314 million and 318 million for the three months ended March 31, 2025 and 2024, 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 NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. (3) In 2025, reflects acquisition-related costs associated with the proposed Calpine merger (4) In 2024, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment (5) Represents elimination of the noncontrolling interest related to certain adjustments

GAAP to Non-GAAP Reconciliation – Adjusted O&M* 32 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M. (1) Reflects all gains and losses associated with ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (2) Reflects the direct cost of sales of certain businesses, which are included in gross margin 20262025Adjusted O&M* Reconciliation ($M) $5,800$5,700GAAP O&M ($225)($200)Decommissioning-Related Activities (1) ($125)($125) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (2) $5,450$5,375Adjusted O&M*

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