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First Quarter 2025 Financial & Operating Results May 1, 2025 NYSE: SM SM-Energy.com
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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,” “preliminary,” “target,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this release include, among other things: certain projections for the full year and second quarter 2025 regarding the Company’s 2025 strategic objectives including operational execution, returning cap ital to stockholders and reducing debt, and maintaining and expanding portfolio quality and depth; inventory quality, duration and expected returns; full year and second quarter 2025 gu idance for capital expenditures, net production, oil percentage, operating costs, G&A, DD&A, exploration expense and cash taxes; the number of wells we plan to drill and complete and the ass ociated activity in each of our operating areas; percentage of expected future net production that is hedged; and plan to process ethane for 2025. These statements involve known and unknow n risks, which may cause SM Energy's actual results to differ materially from results expressed or implied by the forward -looking statements. Future results may be impacted by the risks disc ussed in the Risk Factors section of SM Energy's most recent Annual 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 voluntaril y 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 “First Quarter 2025 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 Denver | Corporate Headquarters Uinta Basin Permian Basin South Texas A PREMIER OPERATOR OF TOP -TIER ASSETS
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4 South Texas NET ACRES~155,000 Top-Tier Assets UINTA BASIN | MIDLAND BASIN | SOUTH TEXAS NET ACRES~63,600 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~111,000 UPTON CRANE DUCHESNE UINTAH
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5 2025 Core Strategic Objectives 1ST QUARTER RESULTS SUPPORT 2025 CORE OBJECTIVES Focus on operational execution (1) Assumes quarterly dividend of $0.20 per share and stock price at close of business on April 23, 2025. ▪ Successful Uinta Basin integration results in cash production margin nearly equal to Midland Basin ▪ Production at high end of guidance | 197.3 MBoe/d, at 53% oil ▪ Recognized by Rystad as leader in sustainability among peers Return capital to stockholders ▪ $0.20 per share cash dividend paid in Q125 | Annualized dividend yield of 3.5%(1) ▪ Reduced debt by $31MM | Progressing toward 1x leverage ▪ Borrowing Base and Lender Commitments reaffirmed at $3.0 billion and $2.0 billion Expand our portfolio of top-tier economic drilling inventory ▪ Uinta Basin Upper Cube Douglas Creek formations | Enverus added 57, sub-$50 breakeven locations, a 28% increase to their prior inventory count ▪ Woodford-Barnett | Continuing to expand understanding of position through the drill bit 1 2 3
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6 Why invest in SM Energy? WHAT DIFFERENTIATES US FROM PEERS 1 2 3 Premier operator with track record of capital efficiency and innovation 10+ years of high-quality, low breakeven, resilient inventory(1) with > 65% average projected return(1) Strong balance sheet Sustainable return of capital program | Demonstrated commitment to increasing fixed dividends and the share repurchase program(2) A leader in stewardship 4 5 (1) 2024 YE Inventory assessment as of January 1, 2025 | Based on flat long-term pricing of $70/Bbl oil, $3.50/MMBtu gas, and $26.60/Bbl NGLs and long-term average cost assumptions | Inventory life assumes 120-130 gross wells per year. | Expected average return based on average well spacing of ~1,400’ per zone for Midland Basin and South Texas. Uinta Basin inventory is normalized to 10k foot laterals as the Company evaluates long-term development plan options. (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 a quarterly dividend of $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. After completing ~$369 million in stock repurchases from 3Q22 through 2Q24, the Board reloaded the existing stock repurchase program in the amount of $500 million and extended the program through December 31, 2027.
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7 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 Gulf Coast (Austin Chalk & Eagle Ford) Focus on Operational Execution SUCCESSFUL UINTA BASIN INTEGRATION | ENVERUS ADDS 57 SUB -$50/ BBL BREAKEVEN LOCATIONS (1) Enverus Intelligence Research | Morning Energy: I’ll Take the Heavy | Andrew Gillick | April 16, 2025. Locations added are sub-$50/bbl breakeven. (2) Enverus data as of April 16, 2025. | Horizontal wells completed post 2010 for XCL Lower Cube and XCL Upper Cube wells, and for the Midland and Western Gulf of Mexico Basins. Uinta Upper Cube Oil Production Competitive with Other Basins(2) Enverus “SM … holds the most at 57 (locations) … which is a material shift in remaining Uinta inventory for SM at 28% higher … we view the Douglas Creek as geologically viable across much of the basin… Those recent buyers may be on to something.”(1) Douglas Creek
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8 Focus on Operational Execution NEW WELLS REACH IP30 IN UINTA BASIN AND SOUTH TEXAS New Wells that Reached IP30 ▪ 6 Lower Cube wells ▪ 1,193 Avg. Boe/d per well ▪ 91% Oil ▪ 12,089’ Avg. lateral length DUCHESNE UINTAH New Wells that Reached IP30 ▪ 4 Austin Chalk wells ▪ 1,061 Avg. Boe/d per well ▪ 55% Oil | 78% Liquids ▪ 11,935’ Avg. lateral length LIQUIDS-RICH GAS OIL DIMMIT WEBB
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9 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 Focus on Operational Execution CONTINUED SIGNIFICANT OIL PRODUCTION OUTPERFORMANCE COMPARED TO PEERS SM Energy Wells v. Austin Chalk Peers(2)SM Energy Wells v. Howard County Peers(1) ~32% 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 ~42% (1) Enverus data as of April 4, 2025. | Horizontal wells completed in Howard County, January 1, 2021 through March 1, 2025. | Peers include APA, Bayswater, Birch Operations, CVX, Double Eagle, 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 April 4, 2025. | Oil production in the West Condensate area of the Austin Chalk. | Horizontal wells completed January 2018 through March 2025. | Peers include CRGY, CVX, Endeavor Natural Gas, and Grit Oil & Gas.
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10 Focus on Operational Execution DRIVING CAPITAL EFFICIENCIES ACROSS ALL THREE CORE BASINS ▪ Success in drilling 3-mile laterals ▪ Record footage completed in March ▪ Record oil takeaway UINTA INTEGRATION ▪ Cost savings with design changes focused on treating pressures ▪ Enhanced production with changes to fluid system ▪ Success in drilling 4-mile laterals PERMIAN DESIGN OPTIMIZATION SOUTH TEXAS COST & CAPITAL EFFICIENCY ▪ Cost savings in using lease gas to fuel completions ▪ Completed $ per foot decreased over 30% since 2022 ▪ Record drilling feet per day and lowest drill out cost per foot
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11 Advanced Analytics Computer Vision Machine Learning Algorithms Predictive Modeling Generative AI Robotic Process Automation Text Analytics Focus on Operational Execution TECHNOLOGY IS PART OF OUR DNA Machine Learning Algorithms ▪ Scale for acquisitions and exploration ▪ Completion design and well spacing optimization Computer Vision ▪ Identification of geophysical attributes Robotic Process Automation ▪ Reduces risk and increases efficiency of land and accounting processes Generative AI ▪ Enterprise-wide enablement with new custom solutions in development Employee empowerment and innovation drives differential performance
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12 1Q25 Performance SUCCESSFUL UINTA BASIN INTEGRATION DRIVES STRONG 1Q RESULTS Note: Amounts may not calculate due to rounding. (1) Indicates a non-GAAP measure or metric. Please refer to the “First Quarter 2025 Non-GAAP Definitions, Reconciliations and Disclosures” sections in the Appendix. $588.9 million1Q25 ADJ. EBITDAX(1) 197.3 MBoe/d 1Q25 NET PRODUCTION $73.8 million 1Q25 ADJ. FREE CASH FLOW(1) $1.761Q25 ADJ. EPS(1) Key Metrics 1Q25 Net Production and Pricing Total Net Production (MMBoe) 17.8 Total Net Production (MBoe/d) 197.3 Oil / Liquids Percentage 53% / 66% Pre-Hedge Realized Price ($/Boe) $47.29 Post-Hedge Realized Price(1) ($/Boe) $47.73 Costs (per Boe) LOE $6.13 Transportation $3.92 Production & Ad Valorem Taxes $2.62 Total Production Expenses $12.67 Cash Production Margin (Pre-Hedge) $34.62 G&A (Cash) $1.90 G&A (Non-Cash) $0.32 DD&A $15.20 Earnings GAAP Earnings (Per Diluted Share) $1.59 Adjusted Net Income(1) (Per Diluted Share) $1.76 Adjusted EBITDAX(1) ($MM) $588.9 Adjusted free cash flow(1) ($MM) Net cash provided by operating activities (GAAP) $483.0 Net change in working capital $31.6 Net cash provided by operating activities before net change in working capital (1) $514.6 Capital expenditures (GAAP) $413.9 Changes in capital expenditure accruals $26.9 Capital expenditures before change in capital expenditure accruals(1) $440.8 Adjusted free cash flow(1) $73.8 Return of Capital ($MM) Share Repurchase $ - Dividends Paid $22.9 Return of Capital ($MM) $22.9
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13 Empowered by a Strong Balance Sheet REDUCED DEBT $31MM | PROGRESSING TOWARDS 1X LEVERAGE Note: Data as of March 31, 2025. (1) Indicates a non-GAAP measure or metric. Please refer to the Please refer to the “First Quarter 2025 Non-GAAP Definitions, Reconciliations and Disclosures” sections 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 two quarters of Adjusted EBITDAX contributing to the trailing twelve-month Adjusted EBITDAX used in the metric as of March 31, 2025. Debt Maturities (millions) as of March 31, 2025: $3.0B Borrowing Base $2.0B Aggregate Revolving Lender Commitments LIQUIDITY: $2.0 billion NET DEBT(1): $2.8 billion As of March 31, 2025: 1.3x 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 $419 $417 $400 $38 $750 $750 $0 $250 $500 $750 $1,000 $1,250 $1,500 $1,750 $2,000 Revolving Credit Facility Senior Notes 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% 103.250% N/A N/A Maturity Date 9/2026 1/2027 7/2028 8/2029 8/2032
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14 Hedging Summary STRATEGY IS TO ALIGN HEDGING WITH LEVERAGE Note: Includes derivative contracts for settlement at any time during the second quarter of 2025, entered into through April 24, 2025. (1) Percent of net production hedged based on 2Q25-4Q25 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 $66.76/Bbl (collar floors and swaps) to $72.51/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 $3.71/MMBtu (collar floors and swaps) to $4.26/MMBtu (collar ceilings and swaps). Percent hedged based on dry gas volumes. 2Q25 – 4Q25 BASIS SWAPS: Basis Swaps Volumes Price Oil MBbls $/Bbl Midland Basin differential ~3,400 $1.18 MEH differential ~1,600 $1.86 Gas BBtu $/MMBtu WAHA differential ~15,400 $(0.72) 2Q25 – 4Q25 SWAPS AND COLLARS:(1) Gas volumes hedged(3) ~44,800 BBtu of expected 2Q25-4Q25 net natural gas production(1) is hedged at a weighted-average price of $3.71/MMBtu to $4.26/MMBtu 38% 34% 0% 50% 100% Oil volumes hedged(2) ~10,200 MBbls of expected 2Q25-4Q25 net oil production(1) is hedged at a weighted-average price of $66.76/Bbl to $72.51/Bbl
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15 2025 Plan Guidance 2Q25 GUIDANCE AND REGIONAL DETAILS (1) Indicates a non-GAAP measure or metric. Please refer to the “First Quarter 2025 Non-GAAP Definitions, Reconciliations and Disclosures” sections in the Appendix. (2) Capital expenditures before change in capital expenditure accruals; inclusive of ~$10 million 2Q non-operated activity already approved; excludes acquisitions and any additional non-operated activity to be evaluated later in the year. (3) 2Q net completions could be impacted by three large pads that straddle the end of the second quarter. (4) Production taxes estimated at ~4.4% of pre-hedge revenue and Ad Valorem taxes estimated at ~$0.52/Boe for FY 2025. (5) 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. (6) Net drills, completions and average lateral length based on operated wells expected to be completed in 2025. Average rig and completion crew activity planned for 2Q. Key Metrics Guidance 2Q25 Guidance FY25 Capital Expenditures(1)(2) $375 – $385 million $1.3 billion Drills (net wells) 25 105 Completions (net wells)(3) 50 150 Total Net Production (MBoe/d) 197 – 203 200 – 215 Oil Percentage 54% – 55% 51% – 52% LOE (per Boe) ~$6.10 ~ $5.90 Transportation (per Boe) $4.10 – $4.40 Production & Ad Valorem Taxes (per Boe)(4) $2.50 – $2.70 DD&A (per Boe) $15 Exploration Expense ($MM) $75 G&A ($MM)(5) $160 Cash Taxes ($MM) $75 – $95 Uinta Basin (6) ▪ ~ 35 drills | 50 completions ▪ ~ 11,200’ average lateral length ▪ 3 rigs | 1 crew Midland Basin (6) ▪ ~ 40 drills | 60 completions ▪ ~ 12,300’ average lateral length ▪ 3 rigs | 1 crew South Texas (6) ▪ ~ 30 drills | 40 completions ▪ ~ 11,000’ average lateral length ▪ 1 rig | 1 crew
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16 Operational Excellence RECOGNIZED BY RYSTAD AS A LEADER IN SUSTAINABILITY AMONG PEERS (1) Data sourced from Rystad Energy | ESG Rankings for 2023: Which US operators excelled in sustainability | April 8, 2025. Peers selected for Rystad analysis include APA, AR, BKV, BP, CHRD, CIVI, CLR, CNX, COP, CRK, CTRA, CVX, DVN, EOG, EQT, EXE, FANG, GPOR, HES, MGY, MTDR, MUR, NFG, OVV, OXY, PR, RRC, VTLE, XOM. Overall ESG Scores for Top 15 Operators(1) 0 50 100 150 200 250 Peer 14 Peer 13 Peer 12 Peer 11 Peer 10 Peer 9 Peer 8 Peer 7 Peer 6 Peer 5 Peer 4 Peer 3 SM Peer 2 Peer 1 Environmental Social Governance SM Energy #1 among oil-focused operators(1)
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17 2025 Core Strategic Objectives CORE OBJECTIVES SUPPORT LONG -TERM PROFITABILITY AND VALUE CREATI ON Focus on operational execution To realize a step change in scale through the successful integration of our Uinta Basin assets; delivering low breakeven, high return wells across the portfolio by optimizing capital efficiency, demonstrating innovation and remaining a leader in stewardship. Return capital to stockholders By generating free cash flow to support our increased $0.80 per share annual fixed dividend, transferring enterprise value to equity holders by pursuing reduced debt to a target of 1 times leverage and resuming our share buyback program. Expand our portfolio of top-tier economic drilling inventory Through acquisition and exploration, and the application of advanced analytics, new technologies and development optimization. 1 2 3
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Appendix
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19 1Q25 Realizations by Region THREE TOP TIER AREAS OF OPERATION Uinta Basin Midland Basin South Texas Total Net Production Volumes Oil (MBbls) 2,997 4,664 1,670 9,332 Gas (MMcf) 2,751 15,992 17,634 36,376 NGL (MBbls) — 5 2,356 2,361 Total (MBoe) 3,456 7,335 6,965 17,756 % Oil 87% 64% 24% 53% Revenue (in thousands) Oil $204,630 $336,427 $117,414 $658,471 Gas $9,462 $56,213 $54,419 $120,094 NGL — $153 $60,902 $61,055 Total $214,092 $392,793 $232,735 $839,620 Expenses (in thousands) Lease operating expense $27,038 $59,375 $22,450 $108,863 Ad valorem tax expense $750 $5,911 $3,152 $9,813 Transportation costs $37,755 $119 $31,681 $69,555 Production taxes $7,106 $19,814 $9,922 $36,842 Per Unit Metrics Realized sales price | Oil Per Bbl $68.27 $72.13 $70.30 $70.56 % of benchmark – WTI 96% 101% 98% 99% Realized sales price | Gas per Mcf $3.44 $3.52 $3.09 $3.30 % of benchmark - NYMEX Henry Hub 94% 96% 85% 90% Realized sales price | NGL per Bbl Nm Nm $25.85 $25.86 % of benchmark – OPIS Nm Nm 83% 83% Realized price per Boe $61.95 $53.55 $33.41 $47.29 Lease operating expense per Boe $7.82 $8.10 $3.22 $6.13 Ad Valorem tax expense per Boe $0.22 $0.81 $0.45 $0.55 Transportation cost per Boe $10.92 $0.02 $4.55 $3.92 Production tax per Boe $2.06 $2.70 $1.42 $2.07 Production tax as % of pre-hedge revenue 3.3% 5.0% 4.3% 4.4% Cash production margin per Boe(1) $40.93 $41.92 $23.77 $34.62 Benchmark Pricing NYMEX WTI Oil ($/Bbl) $ 71.42 NYMEX Henry Hub Gas ($/MMBtu) $ 3.65 OPIS Composite NGL ($/Bbl) $ 31.29 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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20 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 1Q25 1Q25 As of March 31, 2025 Gross Net Gross Net Gross Net Uinta Basin Uinta Basin total 14 10 30 24 32 24 Midland Basin RockStar 16 14 5 3 30 24 Sweetie Peck 9 7 15 9 20 16 Midland Basin total 25 21 20 12 50 40 South Texas (1) Austin Chalk 7 7 5 5 25 25 Eagle Ford & Other 3 3 - - 15 15 South Texas total 10 10 5 5 40 40 Total 49 41 55 41 122 104
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21 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 March 31, 2025. (2) Sweetie Peck acreage includes ~1,050 net drill-to-earn acreage. Net Acres(1) At March 31, 2025 Midland Basin RockStar 83,200 Sweetie Peck(2) 27,500 Midland Basin total 110,700 South Texas 155,000 Uinta Basin 63,600 Rocky Mountain Other 47,400 Other Areas / Exploration 25,000 Total 401,700 ~111,000 MIDLAND BASIN NET ACRES ~155,000 SOUTH TEXAS NET ACRES ~63,600 UINTA BASIN NET ACRES
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22 NGL Realizations 2025 PLAN ASSUMES ETHANE PROCESSING IN 2Q AND 3Q; REJECTING ETHA NE IN 4Q (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% Normal Butane, and 7% Isobutane. Note 2: SM Energy has completed 151 Austin Chalk wells that have reached IP30 as of April 21, 2025. Based on wells to date, average gas shrink by area is: Northern oily area ~21%, South/Eastern liquids-rich gas: ~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; 1Q24 to 3Q24 realizations reflect the processing of ethane Realizations by Quarter 1Q 2025 4Q 2024 3Q 2024 2Q 2024 1Q 2024 OPIS Benchmark(1) Price ($/Bbl) $31.29 $29.29 $26.68 $27.96 $29.28 SM Energy NGL Realization ($/Bbl) $25.86 $24.49 $21.70 $22.86 $22.94 % Differential to OPIS Benchmark(1) 83% 84% 81% 82% 78% AUSTIN CHALK: High Liquids Content % Liquids NGL Yield NGL Bbls/MMcf
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23 Oil Derivative Positions(1) BY QUARTER (1) Includes derivative contracts for settlement at any time during the second quarter of 2025 and later periods, entered into through April 24, 2025. (2) Weighted-average contract price. (3) Volume weighted-average contract price for NYMEX WTI swaps and NYMEX WTI collars. Oil NYMEX WTI Oil Swaps NYMEX WTI Oil Collars Midland - Cushing Oil Basis Swaps MEH – WTI Oil Basis Swaps NYMEX WTI Roll Basis Swaps Weighted-Average Price of Swaps and Collars Period Volume (MBbls) $/Bbl(2) Volume (MBbls) Ceiling $/Bbl(2) Floor $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Volume (MBbls) Price Differential $/Bbl(2) Ceiling $/Bbl(3) Floor $/Bbl(3) Q2 2025 2,479 $70.55 1,178 $81.70 $66.25 1,118 $1.18 544 $1.86 2,410 $0.44 $74.14 $69.17 Q3 2025 2,166 $71.09 1,243 $75.39 $60.22 1,104 $1.18 544 $1.86 2,421 $0.44 $72.66 $67.12 Q4 2025 1,012 $69.99 2,160 $70.70 $60.61 1,178 $1.18 526 $1.86 2,420 $0.44 $70.47 $63.61 Q1 2026 - - 1,365 $64.80 $56.70 1,076 $0.99 391 $2.02 - - $64.80 $56.70 Q2 2026 - - 910 $64.14 $55.00 1,045 $0.99 400 $2.02 - - $64.14 $55.00 Q3 2026 - - - - - 975 $0.99 377 $2.01 - - - - Q4 2026 - - - - - 949 $0.99 378 $2.01 - - - -
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24 Gas and NGL Derivative Positions(1) BY QUARTER (1) Includes derivative contracts for settlement at any time during the second quarter of 2025 and later periods, entered into through April 24, 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 Propane Swaps Purity Ethane Swaps Period Volume (MBbls) $/Bbl(2) Volume (MBbls) $/Bbl(2) Q2 2025 151 $32.81 - - 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 Gas Swaps IF WAHA Gas Swaps IF WAHA Gas Basis Swaps NYMEX Henry Hub Gas Collars IF HSC Gas Swaps Weighted-Average Price of Swaps and Collars Period Volume (BBtu) $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Volume (BBtu) Ceiling $/MMBtu(2) Floor $/MMBtu(2) Volume (BBtu) $/MMBtu(2) Ceiling $/MMBtu(3) Floor $/MMBtu(3) Q2 2025 7,028 $3.89 - - 5,236 $(0.78) 5,893 $3.58 $3.25 - - $3.75 $3.59 Q3 2025 10,257 $4.17 - - 5,117 $(0.72) 7,497 $4.12 $3.24 - - $4.15 $3.78 Q4 2025 6,175 $4.33 - - 5,046 $(0.66) 7,982 $5.31 $3.25 - - $4.89 $3.72 Q1 2026 5,724 $4.41 2,314 $3.16 574 $(1.75) 4,943 $6.12 $3.52 957 $4.07 $4.78 $3.86 Q2 2026 6,988 $3.41 - - - - 3,398 $3.55 $3.25 - - $3.45 $3.36 Q3 2026 6,021 $3.67 520 $2.86 - - 3,505 $4.21 $3.25 - - $3.82 $3.48 Q4 2026 2,673 $3.97 514 $3.22 - - 7,112 $5.43 $3.45 - - $4.94 $3.57 Q1 2027 6,992 $4.32 4,094 $3.63 509 $(0.67) - - - - - $4.07 $4.07 Q2 2027 - - - - - - - - - - - - - Q3 2027 - - - - 499 $(0.75) - - - - - - -
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First Quarter 2025 Non-GAAP Definitions, Reconciliations and Disclosures
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26 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 first 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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27 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 March 31, 2025, amount excludes certain capital expenditures related to unsuccessful exploration activities. (4) The tax effect of adjustments for the three months ended March 31, 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) March 31, 2025 Net income (GAAP) $ 182,269 Net derivative loss 17,216 Net derivative settlement gain 7,751 Other, net 391 Tax effect of adjustments(4) (5,604) Adjusted net income (non-GAAP) $ 202,023 Diluted net income per common share (GAAP) $ 1.59 Net derivative loss 0.15 Net derivative settlement gain 0.07 Other, net — Tax effect of adjustments(4) (0.05) Adjusted net income per diluted common share (non-GAAP) $ 1.76 Basic weighted-average common shares outstanding 114,515 Diluted weighted-average common shares outstanding 114,948 Adjusted EBITDAX(1) Three Months Ended Trailing Twelve Months Ended (in thousands, except per share data) March 31, 2025 March 31, 2025 Net income (GAAP) $ 182,269 $ 821,363 Interest expense 44,373 163,159 Interest income (113) (25,246) Income tax expense 49,732 213,593 Depletion, depreciation, and amortization 269,900 913,017 Exploration(2) 10,311 51,861 Stock-based compensation expense 7,089 27,092 Net derivative (gain) loss 17,216 (60,887) Net derivative settlement gain 7,751 63,193 Other, net 391 (24) Adjusted EBITDAX (non-GAAP) $ 588,919 $ 2,167,121 Interest expense (44,373) (163,159) Interest income 113 25,246 Income tax expense (49,732) (213,593) Exploration(2)(3) (10,311) (50,661) Amortization of deferred financing costs 2,550 8,635 Deferred income taxes 26,259 173,854 Other, net 1,124 (35,276) Net change in working capital (31,564) 77,332 Net cash provided by operating activities (GAAP) $ 482,985 $ 1,989,499
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28 (1) Indicates a non-GAAP measure. See above “Definitions of non-GAAP measures and metrics as Calculated by the Company.” (2) Amounts as of March 31, 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 (in thousands) March 31, 2025 Net cash provided by operating activities (GAAP) $ 482,985 Net change in working capital 31,564 Cash flow from operations before net change in working capital (non-GAAP) $ 514,549 Capital expenditures (GAAP) $ 413,868 Changes in capital expenditure accruals 26,931 Capital expenditures before changes in accruals (non-GAAP) $ 440,799 Adjusted free cash flow (non-GAAP) $ 73,750 Adjusted Net Debt(1) Three Months Ended (in thousands, except per share data) March 31, 2025 Principal amount of Senior Notes(2) $ 2,736,026 Revolving credit facility(2) 37,500 Total principal amount of debt (GAAP) $ 2,773,526 Less: Cash and cash equivalents 54 Net Debt (non-GAAP) $ 2,773,472
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Contact Information Patrick A. Lytle Senior Vice President – Finance 303.864.2502 plytle@sm-energy.com