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NYSE: SM SM-Energy.com EnerCom – Denver The Energy Investment Conference August 18, 2025
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2 Disclaimers Forward-looking Statements This presentation contains forward-looking statements within the meaning of securities laws. The words “believes,” “demonstrate,” “estimate,” “expect,” “intends,” “plan,” “predictions,” “preliminary,” “target,” and similar expressions are intended to identify forward -looking statements. Forward-looking statements in this release include, among other things: certain projections regarding the Company’s 2025 strategic objectives including operational execution, returning capital to stockhold ers and reducing debt, and maintaining and expanding a portfolio of top tier inventory; inventory quality and duration; progress toward achieving our leverage target; expected annual dividend yield; estimated net proved reserves and average net daily production for 2025; full year and third quarter 2025 guidance for capital expenditures, net production, oil percentage, operati ng costs, G&A, DD&A, exploration expense and cash taxes; the number of wells we plan to drill and complete and the associated activity in each of our operating areas; the number of drill ing rigs and frac crews expected to be deployed for the remainder of 2025; percentage of expected future net production that is hedged; plan to process ethane for certain periods in 2025; and predi cted well performance based on machine learning completions optimization. These statements involve known and unknown risks, which may cause SM Energy's actual results to differ material ly from results expressed or implied by the forward-looking statements. Future results may be impacted by the risks discussed in the Risk Factors section of SM Energy's most recent Annu al Report on Form 10-K, and such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission. The forward -looking statements contained herein speak as of the date of this release. Although SM Energy may from time to time voluntarily update its prior forward -looking statements, it disclaims any commitment to do so, except as required by securities laws. Non-GAAP Financial Measures and Metrics This presentation references non-GAAP financial measures and metrics. Please see the “Non- GAAP Definitions, Reconciliations and Disclosures” section of the Appendix, which includes definitions of non-GAAP measures and metrics used in this presentation and reconciliations of non- GAAP measures to the most directly comparable GAAP measure.
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3 SM Energy is… A PREMIER OPERATOR: Capital Efficiency OWNER OF TOP-TIER ASSETS: High-Quality Inventory with Long Runway A LEADER: Sustainability and Stewardship A PREMIER OPERATOR OF TOP -TIER ASSETS Focus on Operational Execution Return Capital to Stockholders Expand Portfolio of Top-Tier Inventory1 2 3 Permian Basin South Texas Uinta Basin Denver | Corporate Headquarters
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4 Step-Change in Scale and Value PROVED RESERVES AND PRODUCTION GROWTH: 5+ YEAR CLIMB (3) SEC Pricing 2020 2021 2022 2023 2024 Oil ($/Bbl) $39.57 $66.56 $93.67 $78.22 $75.48 Gas ($/MMBtu) $1.99 $3.60 $6.36 $2.64 $2.13 NGLs ($/Bbl) $17.64 $36.60 $42.52 $27.72 $28.29 (1) Represents the increase in estimated net proved reserves from December 31, 2020, to December 31, 2024. (2) Represents the increase in average total net daily production (Mboe/d) and average net daily oil production (Mbbl/d) from full-year 2020 to estimated full-year 2025, with 2025 estimates based on the midpoint of full year 2025 guidance. ↑ 64%(2) Total Net Production ↑ 68%(1) Estimated Net Proved Reserves Estimated Net Proved Reserves(3) and Average Net Daily Production 405 492 537 605 678127 141 145 152 170 208 63 77 66 65 80 111 - 50 100 150 200 0 200 400 600 800 1000 2020 2021 2022 2023 2024 2025E Average Net Daily Production (Mboe/d) Estimated Net Proved Reserves (MMBoe) Net Proved Reserves Total Production Oil Production ↑ 76%(2) Oil Production No Dilution, Reduced Leverage, More Value
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5 World Class Technical Team TECHNOLOGY IS PART OF OUR DNA | PROVEN, VALUE- DRIVEN EXPERTISE • Interdisciplinary expertise solving complex challenges • Technology-enabled innovative solutions • Collaborative, inquisitive culture that challenges paradigms • Rapid, adaptive integration of new & emerging technologies
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6 Proven Track Record | Adding Value GROWING INVENTORY THROUGH DIFFERENTIAL GEOSCIENCE CAPABILITY Howard County 79 industry horizontal wells | 2015 3 intervals tested and producing Note: Maps, horizontal well counts, and certain data sourced from Enverus. (1) Source: Enverus as of August 13, 2025. (2) 2023 YE Inventory assessment as of January 1, 2024 | Represents total locations (producing and upside) as noted in SM Energy’s Q423 earnings presentation | Based on flat long-term pricing of $70/Bbl oil, $3.50/MMBtu gas, and $28/Bbl NGLs and long-term average cost assumptions. (3) Enverus Intelligence Research Basin Level data | Half-Cycle breakevens by oil play at 20:1 HH:WTI ($/bbl) as of August 13, 2025. (4) Enverus Intelligence Research Basin Level data | Half-Cycle breakevens by oil play at 20:1 HH:WTI ($/bbl) | provided April 12, 2022. Before SM Energy… Howard County 5,150 industry horizontal wells(1) | Current 9 intervals tested and producing After SM Energy…(1) • Limited data & activity • Questionable economics • Industry skepticism • Peers followed • Top-tier | among lowest break-even • Significant inventory additions West Austin Chalk 8 industry horizontal wells | 2018 ~ $80/Bbl break-even(4) West Austin Chalk 500 industry horizontal wells(1) | Current ~ 465 SM Energy locations(2) ~ $44/Bbl break-even(3)
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7 Focus on Operational Execution CONTINUED OUTPERFORMANCE COMPARED TO PEERS SM Energy Wells v. Austin Chalk Peers(2)SM Energy Wells v. Howard County Peers(1) (1) Enverus data as of July 2025. | Horizontal wells completed in Howard County January 2021 through April 2025. | Peers include APA, Bayswater, Birch Operations, CVX, FANG, HighPeak Energy, HOG Resources, Langford & Brigham, OVV, OXY, Paladin Petroleum, SGY, Spirit O&G Operating, SOGC, VTLE and XOM. (2) Enverus data as of July 2025. | Oil production in the West Condensate area of the Austin Chalk. | Horizontal wells completed January 2018 through April 2025. | Peers include CRGY, CVX, Endeavor Natural Gas, and Grit Oil & Gas. 0 50 100 150 200 250 0 5 10 15 20 25 Avg. Cumulative Oil Production (MBbl/10,000 ft) Months on Production SM Operated Wells Peer Operated Wells 31% 0 50 100 150 200 250 0 5 10 15 20 25 Avg. Cumulative Oil Production (MBbl/10,000 ft) Months on Production SM Operated Wells Peer Operated Wells 43%
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8 Texas: Reliable Execution | Efficiency Gains FASTER DRILLING & COMPLETION | IMPROVED LOGISTICS Note: Calculations are based on changes from FY 2022 to YTD 2025. ↓15% Avg. per Foot D&C Cost ↑64% Avg. per Day Completed Footage + = ↑19% Avg. per Day Drilling Footage Permian – • Improved Woodford drilling footage per day • Engineering well design for ↑ efficiency and ↓ cost South Texas – • Supply chain improvements to ↓ non- productive time • Utilizing lease gas as frac fuel source • Optimized sand logistics
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9 Uinta Basin | Next Chapter, Same Playbook APPLYING OUR SKILLS TO ADD VALUE ~ 4,000’ of stacked play | over-pressured source rocks Lower Cube | over 800 industry horizontal wells(1) Upper Cube | 18 industry horizontal wells(1) Now(1)… Our Future… • Limited activity • Constrained oil takeaway • Uncertain economic viability • Industry skepticism Past… • Sufficient oil takeaway • High quality inventory • Competitive with top tier basins • Significant upside Producing conventionally for over 75 years Extensive data and de-risking from over 8,500 vertical wells (1) Horizontal well counts and certain data sourced from Enverus as of August 14, 2025.
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10 0 50 100 150 200 250 300 350 0 5 10 15 20 25 Avg Cumulative Oil Production (MBbl/10,000 Ft) Months Online SM Upper Cube SM Lower Cube Midland Basin South Texas (Austin Chalk and Eagle Ford) Focus on Operational Execution ESTABLISHING PRESENCE, DRIVING PERFORMANCE IN UINTA BASIN (1) Enverus data as of July 2025. | Horizontal wells completed post 2010 for SM-operated Lower Cube and Upper Cube wells, and for the Midland Basin and the Western Gulf Coast regions. Uinta Basin Oil Production Competitive with Other Basins(1) What SM Energy has demonstrated is unquestionable and bold leadership in deploying cutting edge technology in the Uinta Basin, which benefits the company, the industry, and our communities.” State Senator Ronald M. Winterton
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11 Uinta Basin: Delivering on the Promise INTEGRATION ACHIEVED OPTIMIZATION UNDERWAY (1) The Price River Terminal in Utah is a rail facility that transfers oil from trucks to tanks which is then loaded onto railcar s for transportation to refineries/purchasers across the United States. (2) For wells within certain distance of sand mine | near -term gross well count 30+. (3) Reduces daily truck traffic by ~ 80 vehicles, supporting safer roads and lower emissions. (4) “HRS” indicates pumping hours. Driver of production beat • Optimized marketing boosts oil takeaway • Record daily volume from Price River Terminal (1) Capital efficiency gainsCapital efficiency gains • Record pumping time • First 3-mile lateral drilled in Upper Cube • Remote e-fleet to frac 30+ wells • 100% recycled H2O used in frac during May and June Operated sand mine • Conveyor system deployed • $15 - $30 per lateral foot savings(2) • Reduced trucking(3) & downtime (4) (4)
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12 Operational Excellence SETTING THE STANDARD IN RESPONSIBLE DEVELOPMENT Board and Executive Utah Field Tour Hosted Field Tour Welcomed federal, state, and local officials in partnership with the Utah Petroleum Association and Uintah Basin Technical College — showcasing operational excellence and community collaboration. Expanding Our Community Outreach in Utah . We feel very fortunate to have a company like SM working in Utah. ” State Senator Ronald M. Winterton
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13 $419 $417 $400 $750 $750 $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 Prioritizing Debt Reduction REDUCED NET DEBT (1) ~$140MM| PROGRESSING TOWARDS 1X LEVERAGE TARGET Note: Data as of June 30, 2025. (1) Indicates a non-GAAP measure or metric. Please refer to the “Non-GAAP Definitions, Reconciliations and Disclosures” section in the Appendix. Note, Net Debt-to-Adjusted EBITDAX would be lower on a pro forma basis as the Uinta Basin Acquisition closed October 1, 2024, resulting in only three quarters of Adjusted EBITDAX contr ibuting to the trailing twelve -month Adjusted EBITDAX used in the metric as of June 30, 2025. (2) As of July 15, 2025. Debt Maturities (millions) as of June 30, 2025: $3.0B Borrowing Base $2.0B Aggregate Revolving Lender Commitments LIQUIDITY: $2.1 billion NET DEBT(1): $2.6 billion As of June 30, 2025: 1.2x NET DEBT-TO- ADJUSTED EBITDAX(1) Credit rating agency senior unsecured debt ratings Moody’s: Fitch: S&P: BB- Outlook: Stable BB Outlook: Stable B1 Outlook: Stable Revolving Credit Facility Senior Notes $0 2025 2026 2027 2028 2029 2030 2031 2032 Coupon 6.750% 6.625% 6.500% 6.750% 7.000% Initial Call Date 9/2021 1/2022 7/2024 8/2026 8/2027 Current Call Price 100.000% 100.000% 101.625%(2) N/A N/A Maturity Date 9/2026 1/2027 7/2028 8/2029 8/2032 As of June 30, 2025 ~ $102MM Cash
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14 Sustainable Return of Capital Program SUSTAINABLE FIXED DIVIDEND | 10.1 MILLION SHARES REPURCHASED (1) (1) Cumulative program-to-date as of June 30, 2025. The return of capital program was announced on September 7, 2022, and all repurchased shares of common stock were retired. Total capital returned to stockholders includes $369.1 million of shares repurchased and $220.8 million in dividends paid. Amounts spent to repurchase shares of stock exclude excise taxes, commissions, and fees. (2) At the time of the return of capital program announcement on September 7, 2022, the fixed semi-annual dividend of $0.01 was changed to a quarterly dividend of $0.15 per share and was subsequently increased to $0.18 per share in 2023. In June 2024, the Board approved an increase in SM Energy’s fixed quarterly dividend policy to $0.20 per share, which commenced in the 4th quarter of 2024, reloaded the existing stock repurchase program in the amount of $500 million, and extended the program through December 31, 2027. (3) Indicates a non-GAAP measure or metric. Please refer to the “Non-GAAP Reconciliations and Disclosures” section in the Appendix. Annual Dividend Increased from $0.02 to $0.80 per share(2) Cumulative Capital Returned to Stockholders(1) $589.9 million % FCF(3) Returned to Stockholders(1) 40+% Stock Repurchase Authorization(2) $500 million through 2027
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15 SM Energy is… A PREMIER OPERATOR: Capital Efficiency OWNER OF TOP-TIER ASSETS: High-Quality Inventory with Long Runway A LEADER: Sustainability and Stewardship A PREMIER OPERATOR OF TOP -TIER ASSETS Focus on Operational Execution Return Capital to Stockholders Expand Portfolio of Top-Tier Inventory1 2 3 Permian Basin South Texas Uinta Basin Denver | Corporate Headquarters
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Appendix
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17 PUBLISHED AUGUST 2025 | BASED ON 2024 DATA Note: Unless stated otherwise, the 2024 performance metrics include full -year Uinta Basin assets acquired on October 1, 2024. (1) Improvement noted is 2024 compared to base-year 2019. The 2024 performance data used to calculate the improvement from 2019 is inclusive of the recently acquired Uinta Basin assets. (2) The 2024 disclosures and discussions of the Company’s public targets – established in 2021 using 2019 as the baseline year for Texas operations only – exclude the Uinta Basin assets. (3) Sourced from Rystad Energy | ESG Rankings for 2023: Which US operators excelled in sustainability | April 8, 2025. Updated Sustainability Disclosures (3)
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18 (1) Includes full-year 2024 local taxes paid for the Company’s Texas assets and local taxes paid for the Company’s Uinta Basin assets for the post-effective date period May 1, 2024 – December 31, 2024. (2) Metrics are shown as of December 31, 2024. Effective May 22, 2025, Dr. Stephen R. Brand retired from the Board of Directors of SM Energy Company. Updated Sustainability Disclosures, cont. (1) (2) (2)
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19 South Texas NET ACRES~155,000 Top-Tier Assets UINTA BASIN | MIDLAND BASIN | SOUTH TEXAS NET ACRES~63,700 Uinta Basin Note: Midland Basin and South Texas are as of September 30, 2024. Uinta Basin is as of October 1, 2024, upon closing of the Uinta Basin Acquisitions. DIMMIT WEBB MIDLAND MARTIN DAWSON HOWARD Midland Basin NET ACRES~109,000 UPTON CRANE DUCHESNE UINTAH
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20 Focus on Operational Execution NEW WELLS REACH IP30 IN UINTA BASIN AND SOUTH TEXAS New Wells that Reached IP30 22 Lower Cube wells 1,386 Avg. Boe/d per well 89% Oil 10,447’ Avg. lateral length DUCHESNE UINTAH New Wells that Reached IP30 4 Austin Chalk wells 1,646 Avg. Boe/d per well 52% Oil | 77% Liquids 10,270’ Avg. lateral length LIQUIDS-RICH GAS OIL DIMMIT WEBB Note: Results above were released in the “Second Quarter 2025 Financial & Operating Results” presentation on July 31, 2025.
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21 Subsurface Excellence: New Target APPLYING GEOSCIENCE EXPERTISE DELIVERS INVENTORY AND DIFFERENTIA L RESULTS (1) Enverus data as of July 2025 | Horizontal Woodford and Barnett wells completed in Crane, Ector, Upton and Midland counties, J anuary 2015, through August 2024. | Average of eight wells from two large -cap peers. SM Energy Woodford-Barnett Wells v. Peers(1) 50% 0 50 100 150 200 250 0 2 4 6 8 10 12 14 16 18 Months on Production SM Well 1 SM Well 2 Peer Operated Wells Avg. Cumulative Oil Production Mbbl/10,000 ft)
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22 Subsurface Excellence: New Target APPLYING GEOSCIENCE EXPERTISE DELIVERS INVENTORY AND DIFFERENTIAL RESULTS Klondike Wells Delineation Program Delivering Optimization ** ** ** ** 0 20 40 60 80 100 120 140 160 0 50 100 150 200 Avg. Cumulative Oil Production (MBbl/10,000 ft) Acquisition Model Well 1 Well 2 Well 3 Well 4 Well 5 Well 6 Well 7 Well 8 Days on Production
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23 2025 Core Strategic Objectives 2ND QUARTER STANDOUT PERFORMANCE BUILDS MOMENTUM TOWARDS OBJECTIVES Focus on operational execution (1) Indicates a non-GAAP measure or metric. Please refer to the “Non-GAAP Definitions, Reconciliations and Disclosures” section in t he Appendix. (2) Assumes quarterly dividend of $0.20 per share and stock price at close of business on July 23, 2025. (3) Board approved stock repurchase program in the amount of $500 million through December 31, 2027. Record-breaking Q2 production | 209.1 MBoe/d at 55% oil Strong Q2 financial beat Adj. net income per share(1) of $1.50 Adj. EBITDAX(1) of $570MM Uinta Basin integration complete optimization mode Efficiency gains result in activity acceleration Return capital to stockholders $0.20 per share cash dividend paid in Q2 | Annualized dividend yield of 3% (2) Reduced net debt(1) by ~$140MM in Q2 | Progressing toward 1x leverage target and positioned for stock repurchases (3) Expand our portfolio of top-tier economic drilling inventory Testing new zones on existing acreage to capture incremental value Differentiated by geoscience-led inventory growth 1 2 3
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24 Performing at a High Level UINTA BASIN SHINES Note: Amounts may not calculate due to rounding. (1) Indicates a non-GAAP measure or metric. Please refer to the “Non-GAAP Definitions, Reconciliations and Disclosures” section in the Appendix. $569.6 million2Q25 ADJ. EBITDAX(1) 209.1 MBoe/d 2Q25 NET PRODUCTION $113.9 million 2Q25 ADJ. FREE CASH FLOW (1) $1.50 per share 2Q25 ADJ. NET INCOME(1) Key Metrics 2Q25 Net Production and Pricing Total net production (MMBoe) 19.0 Total net production (MBoe/d) 209.1 Oil / liquids percentage 55% / 68% Pre-hedge realized price ($/Boe) $41.27 Post-hedge realized price(1) ($/Boe) $43.36 Costs (per Boe) LOE $5.52 Transportation $4.13 Production and ad valorem taxes $2.13 Total production expenses $11.78 Cash production margin (pre-hedge) $29.49 G&A (cash) $1.97 G&A (non-cash) $0.24 DD&A $15.40 Earnings GAAP earnings (per diluted share) $1.76 Adjusted net income(1) (per diluted share) $1.50 Adjusted EBITDAX(1) ($MM) $569.6 Adjusted Free Cash Flow(1) ($MM) Net cash provided by operating activities (GAAP) $571.1 Net change in working capital ($69.3) Net cash provided by operating activities before net change in working capital (1) $501.9 Capital expenditures (GAAP) $410.2 Changes in capital expenditure accruals ($22.2) Capital expenditures before change in capital expenditure accruals(1) $388.0 Adjusted free cash flow(1) $113.9 Return of Capital ($MM) Share repurchase $ - Dividends paid $22.9 Return of capital $22.9
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25 2Q25 Realizations by Region THREE TOP TIER AREAS OF OPERATION Midland Basin South Texas Uinta Basin Total Net Production Volumes Oil (MBbls) 4,906 1,814 3,811 10,532 Gas (MMcf) 16,193 16,695 3,357 36,245 NGL (MBbls) 4 2,445 2 2,451 Total (MBoe) 7,609 7,042 4,372 19,024 % Oil 64% 26% 87% 55% Revenue (in thousands) Oil $314,535 $113,480 $225,363 $653,378 Gas $27,215 $44,481 $6,298 $77,994 NGL $109 $53,521 $74 $53,704 Total $341,859 $211,482 $231,735 $785,076 Expenses (in thousands) Lease operating expense $58,491 $23,186 $23,324 $105,001 Transportation costs $118 $31,083 $47,342 $78,543 Production taxes $16,674 $8,806 $4,758 $30,238 Ad valorem tax expense $5,978 $3,185 $1,063 $10,226 Per Unit Metrics Realized sales price | Oil Per Bbl $64.11 $62.54 $59.14 $62.04 % of benchmark – WTI 101% 98% 93% 97% Realized sales price | Gas per Mcf $1.68 $2.66 $1.88 $2.15 % of benchmark - NYMEX Henry Hub 49% 77% 55% 63% Realized sales price | NGL per Bbl Nm $21.89 Nm $21.91 % of benchmark – OPIS Nm 81% Nm 81% Realized price per Boe $44.93 $30.03 $53.00 $41.27 Lease operating expense per Boe $7.69 $3.29 $5.33 $5.52 Transportation cost per Boe $0.02 $4.41 $10.83 $4.13 Production tax per Boe $2.19 $1.25 $1.09 $1.59 Production tax as % of pre-hedge revenue 4.9% 4.2% 2.1% 3.9% Ad Valorem tax expense per Boe $0.79 $0.45 $0.24 $0.54 Cash production margin per Boe(1) $34.24 $20.63 $35.51 $29.49 Benchmark Pricing NYMEX WTI Oil ($/Bbl) $63.74 NYMEX Henry Hub Gas ($/MMBtu) $3.44 OPIS Composite NGL ($/Bbl) $26.99 Note: Amounts may not calculate due to rounding. (1) Cash production margin is calculated as oil, gas, and NGL revenues (before the effects of commodity derivative settlements), less operating expenses (specifically, LOE, transportation, production taxes, and ad valorem taxes). This calculation excludes derivative settlements, G&A, exploration expense, and DD&A and is reflected on a per BOE basis using net equivalent production for the period presented. Cash production margin provides management and the investment community with an understanding of the Company's recurring production margin before G&A, exploration expense, and DD&A , which is helpful to compare period-to-period and across peers.
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26 Activity by Region WELLS DRILLED, FLOWING COMPLETIONS & DUC COUNT (1) The drilled but not completed well count includes 9 gross (9 net) wells that were not included in the Company’s five -year development plan as of December 31, 2024, 8 of which were in the Eagle Ford shale. Wells Drilled Flowing Completions DUC Count 2Q25 2025 YTD 2Q25 2025 YTD As of June 30, 2025 Gross Net Gross Net Gross Net Gross Net Gross Net Midland Basin RockStar 5 4 21 18 20 17 25 20 15 11 Sweetie Peck 15 8 24 15 7 6 22 15 28 18 Midland Basin Total 20 12 45 33 27 23 47 35 43 29 South Texas (1) Austin Chalk 7 6 14 13 13 13 18 18 19 18 Eagle Ford & Other - - 3 3 3 3 3 3 12 12 South Texas Total 7 6 17 16 16 16 21 21 31 30 Uinta Basin Uinta Basin Total 12 9 26 19 21 17 51 41 23 16 Total 39 27 88 68 64 56 119 97 97 75
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27 Plan Intact 2025 GUIDANCE AND REGIONAL DETAILS (1) Indicates a non-GAAP measure or metric. Please refer to the “Non-GAAP Definitions, Reconciliations and Disclosures” section in the Appendix. (2) Production taxes estimated at ~4.4% of pre-hedge revenue and Ad Valorem taxes estimated at ~$0.52/Boe for FY 2025. (3) Full year G&A guidance includes ~$25 million non-cash costs. Included in FY25 G&A are one-time estimated expenses associated with the Uinta Basin integration of ~$7 million. (4) Net drills, completions and average lateral length based on operated and non-operated wells expected to be completed for full-year 2025. Average rig and completion crew activity planned for the second half of 2025. Key Metrics Guidance 3Q25 Guidance FY25 Capital Expenditures(1) $300 – $320 million ~ $1.375 billion Drills (net wells) 25 115 Completions (net wells) 30 150 Total Net Production (MBoe/d) 209 – 215 200 – 215 Oil Percentage 53% – 54% 53% – 54% LOE (per Boe) ~ $5.90 Transportation (per Boe) $4.10 – $4.40 Production & Ad Valorem Taxes (per Boe)(2) $2.50 – $2.70 DD&A (per Boe) $16 Exploration Expense ($MM) $75 G&A ($MM)(3) $160 Cash Taxes ($MM) $10 Uinta Basin(4) FY: ~ 40 drills | 50 completions ~ 11,200’ average lateral length 2H25: 3 rigs | 1 crew Midland Basin(4) FY: ~ 45 drills | 60 completions ~ 12,300’ average lateral length 2H25: 2 rigs | 1 spot crew South Texas(4) FY: ~ 30 drills | 40 completions ~ 11,000’ average lateral length 2H25: 1 rig | 1 spot crew
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28 NGL Realizations 2025 PLAN ASSUMES ETHANE PROCESSING IN 3Q; REJECTING ETHANE IN 4 Q (1) The benchmark is the OPIS NGL composite (both Mont Belvieu Purity Ethane and Non -TET). Helpful Hints for Modeling NGLs: Note 1: SM Energy recovered NGL Composition (assumes ethane processing): 49% Ethane, 24% Propane, 11% Natural Gasoline, 9% Norm al Butane, and 7% Isobutane. Note 2: SM Energy has completed 158 Austin Chalk wells that have reached IP30 as of July 2025. Based on wells to date, average gas sh rink by area is: Northern oily area ~21%, South/Eastern liquids-rich gas area ~19%. NGL price realizations tied to OPIS, fixed fee-based contracts Differential reflects NGL composite barrel product mix as well as transportation and fractionation fees. 1Q25 and 4Q24 realizations reflect the decision to reject ethane at certain gas processing plants due to better economics with strong natural gas prices; 2Q25, 3Q24, and 2Q24 realizations reflect the processing of ethane. Realizations by Quarter 2Q 2025 1Q 2025 4Q 2024 3Q 2024 2Q 2024 OPIS Benchmark(1) Price ($/Bbl) $26.99 $31.29 $29.29 $26.68 $27.96 SM Energy NGL Realization ($/Bbl) $21.91 $25.86 $24.49 $21.70 $22.86 % Differential to OPIS Benchmark (1) 81% 83% 84% 81% 82% AUSTIN CHALK: High Liquids Content % Liquids NGL Yield NGL Bbls/MMcf
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29 Hedging Summary STRATEGY IS TO ALIGN HEDGING WITH LEVERAGE Note: Includes derivative contracts for settlement at any time during the third quarter of 2025 and later periods, entered into thr ough August 13, 2025. (1) Percent of net production hedged based on 3Q25-4Q25 net production and oil percentage guidance. (2) Hedges include oil swaps and collars hedged to NYMEX WTI, excludes basis swaps, at a weighted-average price of $64.82/Bbl (collar floors and swaps) to $70.61/Bbl (collar ceiling and swaps). (3) Hedges include natural gas swaps and collars hedged to NYMEX Henry Hub, excludes basis swaps, hedged to benchmark prices at a weighted -average price of $3.67/MMBtu (collar floors and swaps) to $4.31/MMBtu (collar ceilings and swaps). Percent hedged based on dry gas volumes. 3Q25 – 4Q25 BASIS SWAPS: Basis Swaps Volumes Price Oil MBbls $/Bbl Midland Basin differential ~2,300 $1.18 MEH differential ~1,100 $1.86 Gas BBtu $/MMBtu WAHA differential ~10,200 $(0.69) 3Q25 – 4Q25 SWAPS AND COLLARS:(1) Gas volumes hedged(3) ~36,000 BBtu of expected 3Q25-4Q25 net natural gas production(1) is hedged at a weighted-average price of $3.67/MMBtu to $4.31/MMBtu Oil volumes hedged(2) ~10,000 MBbls of expected 3Q25-4Q25 net oil production(1) is hedged at a weighted-average price of $64.82/Bbl to $70.61/Bbl Strategy aligned with leverage Management of commodity price volatility and risk Downside protection with two-way collars Disciplined and Consistent Program 45% 48% 0% 50% 100%
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30 Oil Derivative Positions(1) BY QUARTER (1) Includes derivative contracts for settlement at any time during the third quarter of 2025 and later periods, entered into thr ough August 13, 2025. (2) Weighted-average contract price. (3) Volume weighted-average contract price for NYMEX WTI swaps and NYMEX WTI collars. Oil NYMEX WTI NYMEX WTI Midland - Cushing MEH – WTI NYMEX WTI Weighted-Average Price of Swaps and CollarsOil Swaps Oil Collars Oil Basis Swaps Oil Basis Swaps Roll Basis Swaps Period Volume (MBbls) $/Bbl(2) Volume (MBbls) Floor $/Bbl(2) Ceiling $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Floor Ceiling $/Bbl(3) $/Bbl(3) Q3 2025 2,668 $71.07 2,247 $61.24 $72.92 1,104 $1.18 544 $1.86 2,421 $0.44 $66.58 $71.92 Q4 2025 1,988 $67.91 3,136 $60.11 $70.28 1,178 $1.18 526 $1.86 2,420 $0.44 $63.14 $69.36 Q1 2026 1,744 $63.03 2,132 $56.80 $65.34 1,076 $0.99 391 $2.02 1,329 $0.35 $59.60 $64.30 Q2 2026 1,303 $62.04 2,213 $55.98 $64.32 1,045 $0.99 400 $2.02 - - $58.23 $63.48 Q3 2026 1,566 $63.85 224 $55.00 $65.73 975 $0.99 377 $2.01 - - $62.75 $64.09 Q4 2026 - - - - - 949 $0.99 378 $2.01 - -
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31 Gas and NGL Derivative Positions(1) BY QUARTER (1) Includes derivative contracts for settlement at any time during the third quarter of 2025 and later periods, entered into th rough August13, 2025. (2) Weighted-average contract price. (3) Volume weighted-average contract price for NYMEX Henry Hub swaps and collars, IF WAHA swaps and IF HSC swaps. NGLs Purity Ethane Swaps Period Volume (MBbls) $/Bbl(2) Q3 2025 - - Q4 2025 123 $13.07 Q1 2026 259 $12.57 Q2 2026 137 $11.71 Q3 2026 137 $11.71 Q4 2026 141 $11.71 Gas NYMEX Henry Hub IF WAHA IF WAHA NYMEX Henry Hub IF HSC Weighted-Average Price of Swaps and CollarsGas Swaps Gas Swaps Gas Basis Swaps Gas Collars Gas Swaps Period Volume (BBtu) $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Volume (BBtu) Floor $/MMBtu(2) Ceiling $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Floor $/MMBtu(3) Ceiling $/MMBtu(3) Q3 2025 10,257 $4.17 1,150 $1.67 5,117 ($0.72) 7,497 $3.24 $4.12 - - $3.65 $4.00 Q4 2025 8,015 $4.37 1,134 $2.02 5,046 ($0.66) 7,982 $3.25 $5.31 - - $3.69 $4.65 Q1 2026 5,724 $4.41 3,461 $2.93 574 ($1.75) 6,743 $3.65 $6.15 957 $4.07 $3.78 $4.78 Q2 2026 9,284 $3.54 2,232 $1.21 - - 3,398 $3.25 $3.55 - - $3.13 $3.20 Q3 2026 9,639 $3.87 3,813 $2.35 - - 3,505 $3.25 $4.21 - - $3.40 $3.60 Q4 2026 4,508 $4.20 514 $3.22 - - 8,952 $3.56 $5.34 - - $3.75 $4.89 Q1 2027 7,888 $4.34 4,094 $3.63 509 ($0.67) 896 $4.00 $5.60 - - $4.09 $4.20 Q2 2027 - - - - - - - - - - - - - Q3 2027 - - - - 1,495 ($0.76) - - - - - - - Q4 2027 - - - - - - - - - - -
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32 Leasehold Summary THREE CORE BASINS WITH SUBSTANTIAL ACREAGE POSITIONS (1) Includes developed and undeveloped oil and natural gas leasehold, fee properties, and mineral servitudes held as of June 30, 2025. (2) Sweetie Peck acreage includes ~1,050 net drill-to-earn acreage. Net Acres(1) At June 30, 2025 Midland Basin RockStar 81,500 Sweetie Peck(2) 27,500 Midland Basin total 109,000 South Texas 155,000 Uinta Basin 63,700 Rocky Mountain Other 47,500 Other Areas / Exploration 25,000 Total 400,200 ~109,000 MIDLAND BASIN NET ACRES ~155,000 SOUTH TEXAS NET ACRES ~63,700 UINTA BASIN NET ACRES
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Midland Basin Operators
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Sweetie Peck Operators
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South Texas Operators
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Uinta Basin Operators
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Non-GAAP Definitions, Reconciliations and Disclosures
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38 Definitions of Non-GAAP Measures and Metrics as Calculated by the Company To supplement the presentation of its financial results prepared in accordance with U.S. generally accepted accounting principles (GAAP), the Company provides certain non-GAAP measures and metrics, which are used by management and the investment community to assess the Company’s financial condition, results of operations, and cash flows, as well as compare performance from period to period and across the Company’s peer group. The Company believes these measures and metrics are widely used by the investment community, including investors, research analysts and others, to evaluate and compare recurring financial results among upstream oil and gas companies in making investment decisions or recommendations. These measures and metrics, as presented, may have differing calculations among companies and investment professionals and may not be directly comparable to the same measures and metrics provided by others. A non-GAAP measure should not be considered in isolation or as a substitute for the most directly comparable GAAP measure or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Reconciliations of the Company’s non-GAAP measures to the most directly comparable GAAP measure is presented below. These measures may not be comparable to similarly titled measures of other companies. Adjusted EBITDAX: Adjusted EBITDAX is calculated as net income before interest expense, interest income, income taxes, depletion, depreciation, amortization and asset retirement obligation liability accretion expense, exploration expense, property abandonment and impairment expense, non-cash stock-based compensation expense, derivative gains and losses net of settlements, gains and losses on divestitures, gains and losses on extinguishment of debt, and certain other items. Adjusted EBITDAX excludes certain items that the Company believes affect the comparability of operating results and can exclude items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. Adjusted EBITDAX is a non-GAAP measure that the Company believes provides useful additional information to investors and analysts, as a performance measure, for analysis of the Company’s ability to internally generate funds for exploration, development, acquisitions, and to service debt. The Company is also subject to financial covenants under the Company’s Credit Agreement, a material source of liquidity for the Company, based on Adjusted EBITDAX ratios. Please reference the Company’s second quarter 2025 Form 10-Q and the most recent Annual Report on Form 10-K for discussion of the Credit Agreement and its covenants. Adjusted free cash flow or FCF: Adjusted free cash flow is calculated as net cash provided by operating activities before net change in working capital less capital expenditures before changes in accruals. The Company uses this measure as representative of the cash from operations, in excess of capital expenditures that provides liquidity to fund discretionary obligations such as debt reduction, returning cash to stockholders or expanding the business. Adjusted net income and Adjusted net income per diluted common share or Adjusted EPS: Adjusted net income and Adjusted net income per diluted common share excludes certain items that the Company believes affect the comparability of operating results, including items that are generally non-recurring in nature or whose timing and/or amount cannot be reasonably estimated. These items include non-cash and other adjustments, such as derivative gains and losses net of settlements, impairments, net (gain) loss on divestiture activity, gains and losses on extinguishment of debt, and accruals for non-recurring matters. The Company uses these measures to evaluate the comparability of the Company's ongoing operational results and trends and believes these measures provide useful information to investors for analysis of the Company's fundamental business on a recurring basis. Net debt: Net debt is calculated as the total principal amount of outstanding senior notes plus amounts drawn on the revolving credit facility less cash and cash equivalents (also referred to as total funded debt). The Company uses net debt as a measure of financial position and believes this measure provides useful additional information to investors to evaluate the Company's capital structure and financial leverage. Net debt-to-Adjusted EBITDAX: Net debt-to-Adjusted EBITDAX is calculated as Net Debt (defined above) divided by Adjusted EBITDAX (defined above) for the trailing twelve-month period (also referred to as leverage ratio). A variation of this calculation is a financial covenant under the Company’s Credit Agreement. The Company and the investment community may use this metric in understanding the Company’s ability to service its debt and identify trends in its leverage position. The Company reconciles the two non-GAAP measure components of this calculation. Post-hedge: Post-hedge is calculated as the average realized price after the effects of commodity net derivative settlements. The Company believes this metric is useful to management and the investment community to understand the effects of commodity net derivative settlements on average realized price.
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39 Non-GAAP Reconciliations (1) Indicates a non-GAAP measure. See above “Definitions of non-GAAP measures and metrics as Calculated by the Company.” (2) Stock-based compensation expense is a component of the exploration expense and general and administrative expense line items on the unaudited condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above will vary from the amount shown on the unaudited condensed consolidated statements of operations for the component of stock-based compensation expense recorded to exploration expense. (3) For the trailing twelve months ended June 30, 2025, amount excludes certain capital expenditures related to unsuccessful exploration activities. (4) The tax effect of adjustments for the three months ended June 30, 2025, was calculated using a tax rate of 22.1% This rate approximates the Company’s statutory tax rate adjusted for the period, as adjusted for ordinary permanent differences. Adjusted Net Income(1) Three Months Ended (in thousands, except per share data) June 30, 2025 Net income (GAAP) $ 201,665 Net derivative gain (78,308) Net derivative settlement gain 39,745 Other, net 409 Tax effect of adjustments(4) 8,432 Adjusted net income (non-GAAP) $ 171,943 Diluted net income per common share (GAAP) $ 1.76 Net derivative gain (0.68) Net derivative settlement gain 0.35 Other, net — Tax effect of adjustments(4) 0.07 Adjusted net income per diluted common share (non-GAAP) $ 1.50 Basic weighted-average common shares outstanding 114,520 Diluted weighted-average common shares outstanding 114,788 Adjusted EBITDAX(1) Three Months Ended Trailing Twelve Months Ended (in thousands, except per share data) June 30, 2025 June 30, 2025 Net income (GAAP) $ 201,665 $ 812,735 Interest expense 42,561 183,913 Interest income (182) (19,095) Income tax expense 50,837 210,840 Depletion, depreciation, and amortization 292,990 1,026,356 Exploration(2) 14,107 50,062 Stock-based compensation expense 5,751 27,055 Net derivative gain (78,308) (127,077) Net derivative settlement gain 39,745 86,415 Other, net 409 (438) Adjusted EBITDAX (non-GAAP) $ 569,575 $ 2,250,766 Interest expense (42,561) (183,913) Interest income 182 19,095 Income tax expense (50,837) (210,840) Exploration(2)(3) (13,868) (49,632) Amortization of deferred financing costs 2,552 9,815 Deferred income taxes 43,204 173,542 Other, net (6,369) (20,955) Net change in working capital 69,265 96,382 Net cash provided by operating activities (GAAP) $ 571,143 $ 2,084,260
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40 (1) Indicates a non-GAAP measure. See above “Definitions of non-GAAP measures and metrics as Calculated by the Company.” (2) Amounts as of June 30, 2025, are from Note 5 – Long-Term Debt in Part I, Item 1 of the Company’s Form 10-Q. Non-GAAP Reconciliations, continued Adjusted Free Cash Flow(1) Three Months Ended Six Months Ended (in thousands) June 30, 2025 June 30, 2025 Net cash provided by operating activities (GAAP) $ 571,143 $ 1,054,128 Net change in working capital (69,265) (37,701) Cash flow from operations before net change in working capital (non-GAAP) $ 501,878 $ 1,016,427 Capital expenditures (GAAP) $ 410,175 $ 824,043 Changes in capital expenditure accruals (22,197) 4,734 Capital expenditures before changes in accruals (non-GAAP) $ 387,978 $ 828,777 Adjusted free cash flow (non-GAAP) $ 113,900 $ 187,650 Adjusted Net Debt(1) (in thousands, except per share data) As of June 30, 2025 Principal amount of Senior Notes(2) $ 2,736,026 Revolving credit facility(2) — Total principal amount of debt (GAAP) $ 2,736,026 Less: Cash and cash equivalents 101,877 Net Debt (non-GAAP) $ 2,634,149
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Contact Information Patrick A. Lytle Senior Vice President – Finance 303.864.2502 plytle@sm-energy.com Meghan Dack Senior Manager – Investor Relations 303.837.2426 mdack@sm-energy.com