Earnings Conference Call Fourth Quarter 2022 February 16, 2023

This presentation contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and ans 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 2022 Annual Report on Form 10-K (to be filed on al Condition and Results of Operations, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19, Commitments and Contingencies, and (d) 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 of the Registrants undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this presentation. Cautionary Statements Regarding Forward-Looking Information 2

The Registrants report their financial results in accordance with accounting principles generally accepted in the United States (GAAP). Constellation supplements the reporting of financial information determined in accordance with GAAP with certain non-GAAP financial measures, including: • Adjusted EBITDA represents earnings before interest, income taxes, depreciation and amortization, and excludes certain costs, expenses, gains and losses and other specified items, including mark-to-market adjustments from economic hedging activities and fair value adjustments related to gas imbalances and equity investments, decommissioning related activity, asset impairments, certain amounts associated with plant retirements and divestitures, pension and other post-employment benefits (OPEB) non-service credits, separation related costs and other items as set forth in the Appendix. Includes nuclear fuel amortization expense. • Adjusted cash flows from operations primarily includes net cash flows from operating activities and Collection of Deferred Purchase Price (DPP) related to the revolving accounts receivable arrangement, which is presented in cash flows from investing activities under GAAP • Free cash flows before growth (FCFbg) is adjusted cash flows from operations less capital expenditures under GAAP for maintenance and nuclear fuel, non-recurring capital expenditures related to separation and Enterprise Resource Program (ERP) system implementation, changes in collateral, net merger and acquisitions, and equity investments and other items as set forth in the Appendix • Adjusted operating revenues excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes in commodity prices • Adjusted purchased power and fuel excludes the mark-to-market impact of economic hedging activities and fair value adjustments related to gas imbalances due to the volatility and unpredictability of the future changes in commodity prices • Total gross margin is defined as adjusted operating revenues less adjusted purchased power and fuel expense, excluding revenue related to decommissioning, gross receipts tax, JExel Nuclear JV, variable interest entities, and net of direct cost of sales for certain end-user businesses • Adjusted operating and maintenance (O&M) excludes direct cost of sales for certain end-user businesses, ARO accretion expense from unregulated units and decommissioning costs that do not affect profit and loss, the impact from operating and maintenance expense related to variable interest entities at Constellation, and other items as set forth in the reconciliation in the Appendix Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be available, as management is unable to project all of these items for future periods. Non-GAAP Financial Measures 3

de 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- tations. 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 measures to the most comparable GAAP measures are provided in the appendices and attachments to this presentation, except for the reconciliation for total gross margin*, which appears on slide 36 of this presentation. Non-GAAP Financial Measures Continued 4

Delivered on Our Commitments in 2022 Enduring Businesses Ready to Meet the Climate Crisis Delivering Value for Our Shareholders Premier ESG Company • Introduced industry-leading climate goals • Issued carbon emissions reports to customers • Published first sustainability report • Launched $1M workforce development program • Created first DEI Advisory Board • Donated more than $12.5M to charitable causes, including $4.6M from employee contributions • 80,000 hours of employee volunteerism Generated ~180 TWhs of clean energy, avoiding ~127 million metric tons of carbon dioxide; equivalent to over 27.5M passenger vehicles being removed for one year • Earned Adjusted EBITDA* of $2,667M, above our revised guidance range • Paid down $2.5B in long-term debt and term loans, and generated strong FCF to support investment grade balance sheet • S&P upgraded to BBB • Paid $185M in dividends • Nuclear capacity factor of 94.8% • 98.4% power dispatch match • 95.8% wind and solar energy capture • Partnered with Microsoft to develop an hourly carbon-free energy matching technology that will allow our customers to have a transparent and independent way to certify that they are meeting their clean energy goals • Secured nuclear fuel supply through 2028 • Pilot program to begin hydrogen production at Nine Mile Point • Hydrogen hubs being encouraged by DOE • Executed two largest CORe deals ever • Ranked overall #1 Retail Energy Supplier in 5

Doubling common dividend, targeting 10% annual future growth Authorized $1.0 billion in share repurchases $1.5 billion of organic growth meeting our double-digit return threshold • Commercial-scale hydrogen project • Nuclear uprates at Byron and Braidwood • Wind repower and refurbishment Credit Ratings • S&P BBB; positive outlook • Baa2; stable outlook Providing Value to Our Shareholders Through Our Capital Allocation Plan Approximately $2.0 billion of additional capital to be allocated in 2023-2024 6

Strong Operations Deliver Reliable and Affordable Carbon-Free Power 7 (1) -owned units. Includes 100% ownership of CENG following closure of EDF Put on August 6, 2021. (2) Excludes Salem. Constellation and Industry averages reflect Oyster Creek and TMI partial year operation in 2018 and 2019, respectively. (3) Major nuclear operator is defined as one entity responsible for the operation of at least two sites and comprising of at least four units; Major Operator rankings reflect 100% ownership for Constellation. (4) Refueling outage values are not adjusted for ownership (5) Composite Operational Excellence Metric consists of 14 indicators in Production, Cost, and Safety. Value represents the percentage of the maximum available score by ranking of Major Operators across the 14 indicators. (6) Power Dispatch Match is used to measure the responsiveness of a unit to the market, expressed as actual energy gross margin relative to total desired energy gross margin. Desired energy gross margin is measured by revenues less fuel costs and variable O&M when unit is dispatched. Wind Energy Capture represents actual energy produced by wind turbine generators of a wind farm, divided by the on-site measured total wind energy available. Solar Energy Capture represents actual energy produced by the sum of the Generating System Modules of a solar plant or group of solar plants, divided by total expected energy to be produced by the sum of the same Generating System Modules. Energy Capture for the combined wind and solar fleet is weighted by the relative site projected pre-tax variable revenue, with deductions made for certain excusable events that are non-controllable. 21 21 22 22 21 35 36 34 32 2018 2019 2020 2021 2022 94.6% 95.7% 95.4% 94.5% 94.8% 90.8% 91.7% 90.8% 90.9% 20222018 2019 2020 2021 Nuclear Capacity Factor (%) (1,2) Average Nuclear Refueling Outage Days (2,4) Nuclear Composite Operational Excellence (5) (Total of Rankings of 14 Indicators) Power Metrics (6) Ranking Among Major Operators (3) 2021 1 2020 1 2019 1 2018 1 Ranking Among Major Operators (2-Yr) (3) 2021 1 2020 1 2019 1 2018 1 Ranking Among Major Operators (3) 2021 1 2020 1 2019 1 2018 2 Industry Average 2019 55.9% 2018 55.8%55.8% 2021 55.9% 2020 73.0% 84.9% 91.3% 92.1% Industry Average 98.1% 97.9% 98.4% 72.4% 98.4%96.1% 96.3% 93.4% 95.7% 95.8% 20192018 2020 2021 2022 Power Dispatch Match Wind & Solar Energy Capture Industry Average

Leading Customer Platform Enables Customers to Meet Their Energy and Sustainability Needs 8 (1) Other includes New England, South and West (2) Leading Customer Operational Metrics (TTM) 2022 Electric Load Served by Region (TWhs) 37 46 14 16 30 13 25 25 Other (1)Midwest New York 16 71 Mid-Atlantic 50 ERCOT 2 55 Wholesale Retail 36% 18% 79% 90% Power New Customer Win Rate Gas New Customer Win Rate C&I Power Customer Renewal Rate C&I Gas Customer Renewal Rate CORe Continues to Grow, Setting Another Record Year Ranked #1 Overall Retail Energy Supplier (2) #1 In Pre-Sale Support #1 In After-Sale Support #1 In Pricing and Contracting • Executed our two largest CORe deals ever • Entered into six long-term power purchase agreements with new build renewable generators across three ISOs, with total nameplate capacity of 824 MWs • 1.65 TWhs will be delivered annually to 12 different customers across 12 states • Approximately 20 TWhs will be delivered over the term of the agreements

Accelerating the Transition to Carbon-Free Future 9 License Renewals Notified NRC of intent to apply for renewals at Clinton and Dresden Nuclear Uprates ~135 additional MWs planned at Byron and Braidwood Hydrogen Hubs DOE encouraged Midwest, Mid-Atlantic and Northeast hubs Hydrogen Production Pilot project at Nine Mile Point will be first nuclear produced hydrogen Direct Air Capture Received grant from DOE to explore carbon removal technology at Byron

10 Always-on Nuclear Keeps the Lights On, Fossil Fails During Grid Emergency • Between December 23-25, Winter Storm Elliott brought record-setting low temperatures to the PJM region, threatening the reliability of the grid and safety of Americans • Always-on nuclear power provided the resiliency and reliability needed by the grid to prevent catastrophic blackouts • 100% during the event (1) • Fossil failed to perform. 23% of PJM capacity failed, nearly 90% of the outages were fossil. • PJM was forced to issue emergency conservation alerts, which were followed by alerts from utilities, g offices, and media outlets (1) Source: https://www.nrc.gov/reading-rm/doc-collections/event-status/reactor-status/2022/index.html (2) Does not include minority ownership share of Salem, which Constellation does not operate (3) Source: https://www.nei.org/news/2023/nuclear-saves-the-holiday-season (4) Other includes nuclear, oil, wind, and solar (5) Source: https://pjm.com/-/media/committees-groups/committees/mic/2023/20230111/item-0x---winter-storm-elliott-overview.ashx 32 GW (71%) 6 GW (13%) Natural Gas 8 GW (16%) Coal Other (4) Total Forced Outages (5) 100% 96% 62% 83% 91% 77% 38% 17% 9% 23% Other (4)CEG Operated Nuclear (2) PJM Nuclear (3) 4%Forced Outage Natural Gas Total PJM (5) Coal Available Capacity Forced Outage vs. Available Capacity

$2,185 $2,667 2021 Results 2022 Results $3,300 2023 Guidance Initiating Full-Year 2023 Adjusted EBITDA* Guidance of $2,900M - $3,300M 11 • Higher realized energy prices • Continued strong performance of customer business • Incremental costs to invest in the business • 14 refueling outages in 2023 versus 11 in 2022 (1) $2,900 ($M) 2023 Year-Over-Year Guidance Drivers $3,100 Delivered 2022 Adj. EBITDA* Above Revised Guidance • Effective portfolio management and strong results in the customer business • PJM capacity performance bonuses, net of non-performance charges • Supporting long-term value: Accelerated investment in growth projects, including hydrogen post- IRA Invested in attracting and retaining top employee talent in competitive job market Margin shaping of retail contracts: 2022 headwinds for fixed price customer contracts that have compelling economics over the term of the contract 2022 Revised Guidance Range $2,450M - $2,650M (1) Includes Constellation-operated nuclear plants and Salem

20 25 30 35 40 45 50 55 60 20 25 30 35 40 45 50 55 60 Market Revenues ($/MWh) M a rk e t R e v e n u e s + P T C ($ / M W h ) 12 PTC Provides Support for Nuclear Units When Revenues Fall Below $43.75/MWh Illustrative Payoff Dynamics for Non-State-Supported Units in 2024 • The PTC provides support of up to $15.00/MWh for units when revenues are between $25.00/MWh and $43.75/MWh while preserving the ability of the unit to participate in upside from commodity markets • The green line assumes revenues of $47.00/MWh and since it is above the $43.75/MWh PTC phase out units would not receive PTC value • When revenues fall below the $43.75/MWh phase out, the PTC will provide support for the units • Assuming revenues of $35.00/MWh, the orange line, we would expect units to receive $7.00/MWh PTC, bringing the total value the unit would receive to $42.00/MWh $47/MWhMerchant Unit Payoff $35/MWh PTC provides support from $25/MWh - $43.75/MWh

Gross Margin Category ($M) (1) 2023 2024 2023 Open Gross Margin* (including South, West, New England, Canada hedged gross margin) $7,000 $6,400 ($1,500) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,800 $2,750 - Mark-to-Market of Hedges (3) ($2,300) ($1,050) $1,500 Power New Business / To Go $400 $300 $100 Non-Power Margins Executed $250 $200 - Non-Power New Business / To Go $200 $350 - Total Gross Margin* (4) $8,350 $8,950 $100 Nuclear PTC Value For Plants Not Supported By State Programs (4,5) N/A - N/A December 31, 2022 Change from September 30, 2022 Gross Margin* Update (1) Gross margin* categories rounded to nearest $50M (2) Includes gross margin* and CMC payments for CMC plants. NY ZEC revenues reflect the expected NY ZEC payment as of current market forwards. Should market forwards exceed the ZEC reference index in New York, ZEC payments may decline. (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2022, market conditions (5) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom Federal PTC Assumptions • There are still many uncertainties about how the nuclear PTC will be calculated, including the definition of gross receipts and interactions with the state programs, that will need to be determined by the IRS before the actual value of the PTC can be known • Although we are advocating that gross receipts be calculated in a manner that accounts for hedging, we have conservatively assumed gross receipts are defined using a spot price • We are working with state policymakers to reduce the amount of state support to account for the federal support provided by the nuclear PTC. However, we have not assumed any reduction in support in these disclosures. • Given these assumptions and 12/31 market prices, we do not currently anticipate receiving any incremental value from nuclear PTCs in 2024 13

Investing for Long-Term Value Through Capital Expenditures (1) 14 $750 $1,000 $775 $800 $850 $1,175 $1,175 $1,175 $400 $575 $525 $1,650 $50 2025E $2,575 2023E2022 $2,475$2,525 2024E Commited Growth BaselineNuclear Fuel ($M) Note: All amounts rounded to the nearest $25M. Items may not sum due to rounding. (1) Reflects cash CapEx for Power at 100% ownership

Investments in Carbon-Free Future that Comfortably Exceed our Double- Digit Return Threshold 15 • Hydrogen facility will initially use ~250 MWs and produce ~33,450 TPA hydrogen, with the ability to expand to 400 MWs – Expect long-term off-take agreements to consume more than 90% of the ~250 MWs • Investing total construction CapEx of ~$900M from 2023-2025 (1) • Hydrogen will be provided to customers co-located at our facility • We anticipate commercial production of hydrogen beginning in 2026 • Increasing nuclear output by ~135 MWs at Byron and Braidwood • Investing ~$800M from 2023-2029 for needed low pressure turbine replacements, upgrading the high pressure turbines and pulling forward planned generator maintenance at Byron, of which ~$200M is growth capital to uprate the plants (2) • Anticipate uprate MWs to be phased in starting in 2026 with full implementation by 2029 based on timing of the turbine installations during planned refuel outages • 315 MWs in initial scope of repowering program • Investing $350 million from 2023-2025 (3) • First 70 MWs partial repowering expected to be in commercial operation in 2023 Growth CapEx Commercial Hydrogen Production Nuclear Uprates Wind Repower & Refurbishment Hydrogen Nuclear Uprates Wind Repower & Refurbishment Note: All amounts rounded to the nearest $25M. Items may not sum due to rounding. (1) Does not assume DOE cost-share through the hydrogen hub (2) $600 million of investment included in baseline CapEx (3) Reflects cash CapEx at 100% ownership; excludes $20 million invested in 2022 ($M) $200 $325 $375 $100 $175 $25 $50 $25 $25 2023 $25 2024 $50 $50 2025 $400 $575 $525 Hydrogen OtherWind Repower & Refurbishment Nuclear Uprates

Securing Nuclear Fuel Supply Through 2028 16 Nuclear Fuel Capital Expenditures • We have built a diverse and resilient portfolio that can withstand a Russian supply disruption • We entered into contracts to increase our inventory to mitigate the risk of possible supply disruption that could occur between now and 2028 the year when multiple Western enrichment providers expect to have additional capacity online • We will continue to work with policymakers and suppliers to ensure reliable sources of supply remain available in the long-term • Fuel costs are expected to rise over coming years but remain under $6/MWh through 2028, even with higher prices Note: All amounts rounded to the nearest $25M (1) ($M) $850 $1,175 $1,175 $1,175 2022 (1) 2023E 2024E 2025E

Adjusted O&M* Flat 2023-2025 17 $4,600 $4,875 $4,850 $4,850 2022 2023E 2024E 2025E ($M) Note: All amounts rounded to the nearest $25M

Our Investment Grade Balance Sheet is a Competitive Advantage 18 35% 45% Pre-WC/ Debt* S&P FFO / Debt* 1.8x Net Debt / EBITDA* (1) 2.2x Book Excluding Non-Recourse (1) 2023 forecasted year-end net debt is $6.7 billion (2) Maturity profile excludes non-recourse debt, P-Cap facility, securitized debt, capital leases, fair value adjustments, unamortized debt issuance costs and unamortized discount/premium (3) Long-term debt balances reflect 2022 Annual Form 10-K GAAP financials, which include items listed in footnote 2 except for the P-Cap facility 2023E Credit Metrics Long-Term Debt Maturity Profile (2) Current Credit Ratings Baa2; stable outlook S&P BBB; positive outlook $ 9 0 0 $ 9 0 0 $ 3 5 0 $ 7 8 8 2 0 3 0 2 0 3 6 2 0 2 3 2 0 2 4 2 0 2 5 2 0 2 9 2 0 3 4 2 0 2 8 2 0 2 6 2 0 2 7 2 0 3 1 2 0 3 2 2 0 3 7 2 0 3 3 2 0 3 5 2 0 3 9 2 0 3 8 2 0 4 0 2 0 4 1 2 0 4 2 Long-Term Debt Balances (3) Recourse $3.0B Non-Recourse $1.6B Total Long-Term Debt $4.6B As of 12/31/2022 ($M)

Strong Free Cash Flows Create Value Through Growth and Capital Return 19 (1) Beginning Cash Available reflects excess cash balance above minimum targets as of December 31, 2022 (2) Available Cash is a midpoint of a range based on December 31, 2022, market prices (3) Debt Issuance & Other Financing includes collateral activity, and contributions from and distributions to JV partners (4) Separation O&M / CapEx includes costs and investments related to separation and multi-year implementation of Enterprise Resource Program (ERP) system $3.8 - $4.2 Separation O&M / CapEx (4) $0.2 Dividend ($0.2) 2023 - 2024 Available Cash (2) $0.6 - $1.0 Debt Issuance & Other Financing (3) ($1.0) Identified Growth ($0.8) ($1.0) Authorized Share Repurchases FCFbg* $1.8 - $2.2 Unidentified Growth / Return of Capital Beginning Cash Available (1) $3.9 - $4.3 ($B)

2023 Priorities 20 Continue as leader in operational excellence Accelerate transition to carbon-free future Work with Treasury and states to implement the IRA provisions Deliver on financial commitments Attract and retain the best talent as a premier workplace Effectively deploy capital to the benefit of our shareholders

Additional Disclosures 21

22

E S G Environmental: • Clean Energy Leadership: Continue to be the cleanest supplier of power in the U.S. and maintain leadership through our climate commitment to own 100% carbon-free generation by 2040. • Investing in a Clean Energy Economy: Leverage our platform to impact customers through enabling new clean energy products and services and providing our customers with an accounting of their carbon emissions and ways to reduce their carbon footprint. • Protecting the Environment: Minimize the impacts of our operations on local air quality, water resources and biodiversity through robust environmental programs. Social: • DEI: Foster a culture of innovation and deliver strong performance by prioritizing a respectful workplace, ensuring a sense of belonging, providing opportunities for growth, attracting and retaining passionate and talented people, and integrating diversity as a business imperative and core value. • Supplier Diversity: Increase diverse supplier spend by expanding Constellation Diverse Business Empowerment strategy internally and externally with supplier diversity councils and other stakeholders. • Community Engagement: Act as a catalyst for positive change in our community, with a focus on employee giving and volunteerism and equity through STEM, scholarships, and workforce development opportunities. Governance: • Board & Executive Governance: Provide effective leadership and guidance to drive our sustainability efforts and deliver on our purpose to accelerate the transition to a carbon-free future. • Act with Integrity: Maintain a comprehensive ethics and compliance program that can adapt to the changing risks we face and guide us as we deliver on our purpose. 23

24 Q4 2022 Adjusted EBITDA* $1,027 $605 $109 $133 ($56) Labor, Contracting and Materials Q4 2022Lower NEIL Distributions ($139) PJM Performance Bonuses, Net Nuclear Outages Q4 2021 ($117) Capacity Revenues ($95) Impact of the February 2021 Extreme Cold Weather Event ($83) ($131) Market and Portfolio Conditions Impact of CTV Investments ($43) Other ($M)

25 Full Year 2022 Adjusted EBITDA* $1,132 $109 ($295) 2021 ($131) Impact of CTV Investments Lower NEIL Distributions ($17) 2022Market and Portfolio Conditions Impact of the February 2021 Extreme Cold Weather Event $70 $74 OtherNuclear Fuel Costs PJM Performance Bonuses, Net ($377) $2,667 $2,185 ($83) Capacity Revenues Labor, Contracting and Materials ($M)

• 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) 26 (1) See H.R. 5376 for additional details; all numbers assume that prevailing wage requirements are satisfied (2) Annual inflation adjustment is consistent with past published guidance for renewable energy credits, published annually PTC Overview Example Assuming 2%, 3% and 4% Inflation (2) PTC Inflation Adjustment • The PTC is in effect beginning after 12/31/23 and through 12/31/32 • In the base year 2024, Constellation qualifies for the nuclear PTC up to $15.00/MWh; the PTC amount is reduced by 80% of gross receipts exceeding $25.00/MWh, phasing out completely after $43.75/MWh • The nuclear PTC can be credited against taxes or monetized by transferring to an eligible taxpayer 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

Extending the Life of our Nuclear Fleet to 80 years 27 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 16,000 18,000 20,000 22,000 20502022 20352030 C a p a c it y ( M W ) 2025 2040 2045 2055 2060 2065 2070 Potential Subsequent License Renewal for Remaining Fleet Clinton License Renewal (60 Years) Dresden Subsequent License Renewal (80 Years) Clinton Subsequent License Renewal (80 Years) Peach Bottom Subsequent License Renewal (80 Years) (1) Current License Life of Fleet (1) icenses out to 2053 and 2054. On February 24, the NRC issued orders in the Peach Bottom and Turkey Point adjudicatory proceedings (which had not been terminated even though the NRC had already issued the renewed licenses) finding that s in place but directed the staff to amend the Peach Bottom licenses to change the expiration dates to the initial renewed license period (2033 and 2034) until the NRC updates its generic environmental analysis and regulations, which is expected to be completed in 2024. Please refer to 2022 Annual Form 10-K for additional information.

28 100% 100% 100% Of our owned generation will be carbon-free by 2040 Reduction of our operations- driven emissions by 2040 (1) Of C&I customers provided with specific information about how to meet GHG reduction goals ✓Clean Energy Supply: ▪ Clean Electricity Supply: We commit that our owned generation supply will be 100% carbon-free by 2040; with an interim goal of 95% carbon- free by 2030 subject to policy support and technology advancements. ▪ Operational Emissions Reduction Goal: We aspire to reduce operations driven emissions by 100% by 2040 subject to technology and policy advancement ▪ Interim target to reduce carbon emissions by 65% from 2020 levels by 2030 ▪ thane pledge ▪ Supply Chain Engagement: Partner with our key energy suppliers on their GHG emissions and climate adaptation strategies ✓Clean Customer Transformation: ▪ Provided 100% of C&I customers with customer- specific information on their GHG impact for facilities contracting for power and gas supply from Constellation including mitigation opportunities that include 24/7 clean electric use ▪ ✓Technology Enablement and Commercialization: ▪ Commit to enable the future technologies and business models needed to drive the clean energy economy to improve the health and welfare of communities through venture investing and R&D. We will target 25% of these investments to minority and women led businesses and will require investment recipients to disclose how they engage in equitable employment and contracting practices, using performance as a factor when considering investments (1) Any emissions that cannot be technologically reduced by that time will be offset; includes all GHGs except methane which is addressed in a separate methane reduction goal

New York ZEC Price Determination 29 Tranche Date U.S. SCC ($/Short Ton) Baseline RGGI Estimate ($/Short Ton) Net CO2 Externality ($/Short Ton) Short Ton to MWh (Conversion Factor) Adjusted SCC ($/MWh) Reference Price ($/MWh) Energy and Capacity Forecast Adjustment ($/MWh) Upstate ZEC Price ($/MWh) Tranche 1 4/1/2017- 3/31/2019 $42.87 $10.41 $32.47 0.53846 $17.48 N/A N/A $17.48 Tranche 2 4/1/2019- 3/31/2021 $46.79 $10.41 $36.38 0.53846 $19.59 $39.00 N/A $19.59 Tranche 3 4/1/2021- 3/31/2023 $50.11 $10.41 $39.71 0.53846 $21.38 $39.00 N/A $21.38 Tranche 4 4/1/2023- 3/31/2025 $54.66 $10.41 $44.26 0.53846 $23.83 $37.78 $5.56 $18.27 Tranche 5 4/1/2025- 3/31/2027 $59.54 $10.41 $49.13 TBD TBD $37.78 TBD TBD Tranche 6 4/1/2027- 3/31/2029 $64.54 $10.41 $54.13 TBD TBD $37.78 TBD TBD

Commercial Disclosures December 31, 2022 30

Open Gross Margin* Generation Gross Margin* at current market prices, including ancillary revenues, nuclear fuel amortization and fuel expense Power Purchase Agreement (PPA) Costs and Revenues Provided at a consolidated level for all regions (includes hedged gross margin* for South, West, New England and Canada (1)) Contracted Revenues Expected contracted revenues from CMC payments to eligible IL plants Expected capacity revenues for generation of electricity Expected revenues from Zero Emissions Credits (ZEC) MtM of Hedges (2) Mark-to-Market (MtM) of power, capacity and ancillary hedges, including cross commodity, retail and wholesale load transactions Provided directly at a consolidated level for four major regions. Provided indirectly for each of the four major regions via Effective Realized Energy Price (EREP), reference price, hedge %, and expected generation. Business Retail, Wholesale planned electric sales Portfolio Management new business Mid marketing new business Executed Retail, Wholesale executed gas sales Energy Efficiency (3) Constellation Home (3) New Business Retail, Wholesale planned gas sales Energy Efficiency (3) Constellation Home (3) Portfolio Management / origination fuels new business Proprietary trading (4) Components of Gross Margin* Categories 31 Margins move from new business to MtM of hedges over the course of the year as sales are executed (5) course of the year Gross margin* linked to power production and sales Gross margin* from other business activities (1) Hedged gross margins* for South, West, New England & Canada region will be included with Open Gross Margin*; no expected generation, hedge %, EREP or reference prices provided for these regions (2) MtM of hedges provided directly for the four larger regions; MtM of hedges is not provided directly at the regional level but can be easily estimated using EREP, reference price and hedged MWh (3) (4) on (5) Margins for South, West, New England & Canada regions and optimization of fuel and PPA activities captured in Open Gross Margin*

Gross Margin Category ($M) (1) 2023 2024 2023 Open Gross Margin (including South, West, New England & Canada hedged GM)* $7,000 $6,400 ($1,500) Contracted Revenues (Capacity, ZEC and IL CMC Plant Revenues) (2) $2,800 $2,750 - Mark-to-Market of Hedges (3) ($2,300) ($1,050) $1,500 Power New Business / To Go $400 $300 $100 Non-Power Margins Executed $250 $200 - Non-Power New Business / To Go $200 $350 - Total Gross Margin* (4) $8,350 $8,950 $100 Nuclear PTC Value for Plants Not Supported By State Programs (4,5) N/A - - Reference Prices (4) 2023 2024 2023 Henry Hub Natural Gas ($/MMBtu) $4.26 $4.27 ($1.17) Midwest: NiHub ATC prices ($/MWh) $49.82 $47.52 ($14.64) Mid-Atlantic: PJM-W ATC prices ($/MWh) $61.18 $58.34 ($13.90) ERCOT-N ATC Spark Spread ($/MWh) HSC Gas, 7.2HR, $2.50 VOM $20.30 $16.71 $1.24 New York: NY Zone A ($/MWh) $41.27 $38.52 ($6.49) December 31, 2022 Change from September 30, 2022 Gross Margin* 32 (1) Gross margin* categories rounded to nearest $50M (2) NY ZEC revenues reflect the expected NY ZEC payment as of current market forwards. Should market forwards exceed the ZEC reference index in New York, ZEC payments may decline. (3) Mark-to-Market of Hedges assumes mid-point of hedge percentages (4) Based on December 31, 2022, market conditions (5) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom

Generation and Hedges 2023 2024 2023 Expected Generation (GWh) (1) 196,500 198,200 (1,400) Midwest (Total) (2) 95,500 96,400 (100) Midwest (Excluding CMCs) 41,300 42,300 (100) Mid-Atlantic 54,800 56,400 (700) ERCOT 20,400 20,100 (600) New York 25,800 25,300 - % of Expected Generation Hedged (3) 94%-97% 75%-78% 1% - 4% Midwest (Total) 95%-98% 83%-86% 0% - 3% Midwest (Excluding CMCs) 91%-94% 63%-66% 2% - 5% Mid-Atlantic 100%-103% 73%-76% 0% - 3% ERCOT 90%-93% 61%-64% 14% - 17% New York 79%-82% 60%-63% (7%) - (4%) Effective Realized Energy Price ($/MWh) (4) Midwest (Excluding CMCs) $29.50 $35.50 $0.50 Mid-Atlantic $46.50 $45.00 $1.00 ERCOT (5) $6.00 $9.00 $5.00 New York $21.50 $33.00 ($3.00) December 31, 2022 Change from September 30, 2022 Generation and Hedges 33 (1) Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted for capacity based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load following products, and options. Expected generation assumes 14 refueling outages in 2023 and 13 in 2024 at Constellation-operated nuclear plants and Salem. Expected generation assumes capacity factors of 94.1% and 94.2% in 2023 and 2024, respectively at Constellation-operated nuclear plants, at ownership. These estimates of expected generation in 2022 and 2023 do not represent guidance or a forecast of future results as we have not completed its planning or optimization processes for those years. (2) Midwest (Total) expected generation includes generation from CMC plants of 54,200 GWh in 2023 and 54,100 GWh in 2024 (3) Percent of expected generation hedged is the amount of equivalent sales divided by expected generation. It includes all hedging products, such as wholesale and retail sales of power, options and swaps. The Midwest values in the table reflect IL plants receiving CMC payments as 100% hedged. To align with the Midwest EREP, however, one should exclude plant and hedge volumes associated with CMC payments. New York values include the effect of the New York ZEC. (4) Effective realized energy price is representative of an all-in hedged price, on a per MWh basis, at which expected generation has been hedged. It is developed by considering the energy revenues and costs associated with our hedges and by considering the natural gas that has been purchased to lock in margin. It excludes uranium costs, RPM capacity, ZEC and CMC revenues, but includes the mark-to-market value of capacity contracted at prices other than RPM clearing prices including our load obligations. It can be compared with the reference prices used to calculate open gross margin* in order to determine the mark-to- (5) Spark spreads shown for ERCOT

Sensitivities (with existing hedges) (1,2) 2023 2024 2023 2023 2024 NiHub ATC Energy Price + $5.00/MWh - $65 ($15) - - - $5.00/MWh - ($65) $15 - $30 PJM-W ATC Energy Price + $5.00/MWh - $60 ($20) - - - $5.00/MWh - ($60) $10 - - NYPP Zone A ATC Energy Price + $5.00/MWh $20 $55 $5 - - - $5.00/MWh ($20) ($55) ($5) - - Nuclear Capacity Factor +/- 1% +/- $65 +/- $65 $(15) Nuclear PTC Value For Plants Not Supported By State Programs (3) December 31, 2022December 31, 2022 Change from September 30, 2022 Gross Margin Sensitivities 34 (1) Sensitivities rounded to the nearest $5M (2) Based on December 31, 2022, market conditions and hedged position; power price sensitivities are derived by adjusting the power price assumption while keeping all other price inputs constant; due to correlation of the various assumptions, the hedged gross margin* impact calculated by aggregating individual sensitivities may not be equal to the hedged gross margin* impact calculated when correlations between the various assumptions are also considered; sensitivities based on commodity exposure which includes open generation and all committed transactions. (3) Plants included are Calvert Cliffs, LaSalle, Limerick and Peach Bottom

Row Item Midwest (Excl. CMCs) (2) Mid-Atlantic ERCOT (3) New York (A) Start with fleet-wide open gross margin* (B) Contracted Revenues (C) Expected Generation (TWh) 42.3 56.4 20.1 25.3 (D) Hedge % (assuming mid-point of range) 64.5% 74.5% 62.5% 61.5% (E=C*D) Hedged Volume (TWh) 27.3 42.0 12.6 15.6 (F) Effective Realized Energy Price ($/MWh) $35.50 $45.00 $9.00 $33.00 (G) Reference Price ($/MWh) $47.52 $58.34 $16.71 $38.52 (H=F-G) Difference ($/MWh) ($12.02) ($13.34) ($7.71) ($5.52) (I=E*H) Mark-to-Market value of hedges ($ million) (1) ($330) ($560) ($95) ($85) (J=A+B+I) Hedged Gross Margin* ($ million) (K) Power New Business / To Go ($ million) (L) Non-Power Margins Executed ($ million) (M) Non-Power New Business / To Go ($ million) (N=J+K+L+M) Total Gross Margin* $200 $350 $8,950 million $6.4 billion $8,100 $300 $2.75 billion Illustrative Example of Modeling 2024 Total Gross Margin* 35 (1) Mark-to-market rounded to the nearest $5M (2) Uses the Midwest hedge ratio that excludes the CMC plant volume and hedges (3) Spark spreads shown for ERCOT

Additional Constellation Modeling Data 36 Total Gross Margin* Reconciliation ($M) (1) 2023 2024 Adjusted Operating Revenues* (2) $30,350 $31,750 Adjusted Purchased Power and Fuel* (2) ($21,500) ($22,325) Wind Production Tax Credits (PTC) ($25) ($25) Other Revenues (3) ($225) ($225) Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses ($250) ($225) Total Gross Margin* (Non-GAAP) $8,350 $8,950 Note: 329 million average outstanding diluted shares as of December 31, 2022, per Annual Form 10-K (1) Items may not sum due to rounding. All amounts rounded to the nearest $25M (2) Excludes the mark-to-market impact of economic hedging activities due to the volatility and unpredictability of the future changes to power prices (3) Other Revenues primarily reflects revenues from variable interest entities, funds collected through revenues for decommissioning the former PECO nuclear plants through regulated rates and gross receipts tax revenues (4) Other primarily reflects noncontrolling interest and Other Revenues (excluding gross receipts tax revenue) (5) Cash tax rate includes receivable from Exelon for tax credits. If receivable were to be excluded in calculation, cash tax rate would be 13% in 2023 and 26% in 2024. Inputs ($M) 2023 2024 Adjusted O&M* ($4,875) ($4,850) Wind PTCs $25 $25 Other (4) $25 ($25) Taxes Other Than Income (TOTI) ($425) ($450) Effective Tax Rate 28% 27% Cash Tax Rate (5) 0% 19%

Appendix Reconciliation of Non-GAAP Measures 37

S&P FFO/Debt (2) = FFO (a) CFO Pre-WC/Debt (3) = CFO (Pre-WC) (c) Adjusted Debt (b) Adjusted Debt (d) S&P FFO Calculation (2) -WC Calculation (3) GAAP Operating Income Cash Flow From Operations + Depreciation & Amortization +/- Working Capital Adjustment = EBITDA - Nuclear Fuel Capital Expenditures - Interest +/- +/- Cash Taxes = CFO Pre-Working Capital (c) + Nuclear Fuel Amortization +/- Mark-to-Market Adjustments (Economic Hedges) +/- Other S&P Adjustments = FFO (a) S&P Adjusted Debt Calculation (2) (3) Long-Term Debt Long-Term Debt + Short-Term Debt + Short-Term Debt + Purchase Power Agreement and Operating Lease Imputed Debt + Underfunded Pension (pre-tax) + Pension/OPEB Imputed Debt (after-tax) +Operating Lease Imputed Debt + AR Securitization Imputed Debt +/- - Off-Credit Treatment of Non-Recourse Debt = Adjusted Debt (d) - Cash on Balance Sheet +/- Other S&P Adjustments = Adjusted Debt (b) GAAP to Non-GAAP Reconciliations (1) 38 (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)

Net Debt/EBITDA = Net Debt (a) Net Debt/EBITDA Excluding Non-Recourse = Net Debt (c) Adjusted EBITDA* (b) Adjusted EBITDA* (d) Net Debt Calculation Net Debt Calculation Excluding Non-Recourse Long-Term Debt (including current maturities) Long-Term Debt (including current maturities) + Short-Term Debt + Short-Term Debt - Cash on Balance Sheet - Cash on Balance Sheet = Net Debt (a) - Non-Recourse Debt = Net Debt Excluding Non-Recourse (c) Adjusted EBITDA* Calculation Adjusted EBITDA* Calculation Excluding Non-Recourse GAAP Net Income GAAP Net Income + Income Tax Expense + Income Tax Expense + Interest Expense, Net + Interest Expense, Net + Depreciation & Amortization + Depreciation & Amortization +/- Adjustments +/- Adjustments = Adjusted EBITDA* (b) - EBITDA from Projects Financed by Non-Recourse Debt = Adjusted EBITDA* Excluding Non-Recourse Debt (d) GAAP to Non-GAAP Reconciliations (1) 39 (1) Due to the forward-looking nature of some forecasted non-GAAP measures, information to reconcile the forecasted adjusted (non-GAAP) measures to the most directly comparable GAAP measure may not be currently available; therefore, management is unable to reconcile these measures

Three Months Ended December 31, Twelve Months Ended December 31, Adjusted EBITDA* Reconciliation ($M) 2021 2022 2021 2022 GAAP Net Income (Loss) $42 $34 ($205) ($160) Income Taxes (1) $117 $133 $225 ($339) Depreciation and Amortization (2) $268 $272 $3,003 $1,091 Interest Expense, Net $72 $64 $297 $251 Unrealized (Gain)/Loss on Fair Value Adjustments (3) $771 $413 ($420) $1,058 Asset Impairments (4) $4 - $541 - Plant Retirements & Divestitures (5) $11 ($7) ($4) ($11) Decommissioning-Related Activities (6) ($275) ($306) ($1,289) $820 Pension & OPEB Non-Service Credits ($14) ($31) ($50) ($116) Separation Costs (7) $24 $41 $49 $140 COVID-19 Direct Costs (8) $11 - $35 - Acquisition Related Costs (9) - - $21 - ERP System Implementation Costs (10) $3 $6 $14 $22 Change in Environmental Liabilities $5 ($2) $12 $10 Cost Management Program - - $9 - Prior Merger Commitment (11) - - - ($50) Noncontrolling Interests (12) ($12) ($12) ($53) ($49) Adjusted EBITDA* $1,027 $605 $2,185 $2,667 GAAP to Non-GAAP Reconciliation 40 Note: Items may not sum due to rounding (1) Includes amounts contractually owed to Exelon under the Tax Matters Agreement (TMA) reflected in Other, net (2) Includes the accelerated depreciation associated with early plant retirements (3) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments (4) Reflects an impairment in the New England asset group, an impairment as a result of the sale of the Albany Green Energy biomass facility, and an impairment of a wind project (5) In 2021, primarily reflects nuclear fuel amortization for Byron and Dresden, partially offset by a gain on sale of our solar business and a reversal of one-time charges resulting from the reversal of the previous decision to retire Byron and Dresden. (6) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units (7) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (8) Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of employees (9) Reflects costs related to the acquisition of Electricite de France SA's (EDF's) interest in Constellation Energy Nuclear Group, LLC (CENG), which was completed in the third quarter of 2021 (10) Reflects costs related to a multi-year ERP system implementation (11) Reversal of a charge related to a prior 2012 merger commitment (12) Represents elimination of the noncontrolling interest related to certain adjustments. In 2022, primarily relates to CRP and in 2021, primarily relates to CENG and the noncontrolling interest portion of a wind project impairment recognized within CRP.

Adjusted EBITDA* Reconciliation ($M) 2023 GAAP Net Income $550 - $850 Income Taxes $425 Interest Expense $425 Depreciation and Amortization $1,125 Unrealized (Gain)/Loss on Fair Value Adjustments (1) $400 Pension and OPEB Non-Service Credits ($50) Decommissioning Related Activity (2) $50 Separation Costs (3) $75 ERP System Implementation (4) $25 Noncontrolling Interest (5) ($50) Other ($25) Adjusted EBITDA* (Non-GAAP) $2,900 - $3,300 GAAP to Non-GAAP Reconciliation 41 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M (1) Includes mark-to-market on economic hedges and fair value adjustments related to gas imbalances and equity investments. (2) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral 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 TSA (4) Reflects costs related to a multi-year ERP system implementation (5) Represents elimination of the noncontrolling interest related to certain adjustments

GAAP to Non-GAAP Reconciliation 42 Adjusted O&M* Reconciliation ($M) 2022 2023 2024 2025 GAAP O&M $4,850 $5,425 $5,275 $5,250 Decommissioning (1) $75 ($200) ($200) ($175) Prior Merger Commitment (2) $50 - - - Direct cost of sales incurred to generate revenues for certain Commercial and Power businesses (3) ($225) ($250) ($225) ($225) Separation Costs (4) ($125) ($75) - - ERP System Implementation (5) ($25) ($25) - - Adjusted O&M* (Non-GAAP) $4,600 $4,875 $4,850 $4,850 Note: Items may not sum due to rounding. All amounts rounded to the nearest $25M. (1) Reflects all gains and losses associated with NDT, ARO accretion, ARO remeasurement, and any earnings neutral impacts of contractual offset for Regulatory Agreement Units. (2) 2022 reflects reversal of a charge related to a prior 2012 merger commitment (3) Reflects the direct cost of sales of certain businesses, which are included in Total Gross Margin* (4) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA (5) Reflects costs related to a multi-year ERP system implementation

GAAP to Non-GAAP Reconciliation 43 Free Cash Flow before Growth* ($M) 2023 - 2024 Adjusted Cash Flows from Operations* (Non-GAAP) (1) $8,050 - $8,450 Baseline and Nuclear Fuel Capital Expenditures ($4,000) Reinvestment in Nuclear Decommissioning Trust Funds (2) ($450) Collateral activity $150 O&M related to Separation and ERP System Implementation $100 Other Net Investing Activities ($50) Free Cash Flow before Growth* $3,750 - $4,150 Note: All amounts rounded to the nearest $50M. Items may not sum due to rounding (1) Includes Collection of Deferred Purchase Price (DPP) related to the revolving accounts receivable arrangement, which is presented in cash flows from investing activities for GAAP. Cash flows from collection of DPP are not forecasted. (2) Reflects reinvestment of proceeds from nuclear decommissioning trust funds that are presented in Adjusted Cash Flows from Operations*. Impact is cash flow neutral.

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