Slides
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SM ENERGY Second Quarter 2026 August 5 , 2026 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 “action,” “anticipate,” “deliver,” “demonstrate,” “establish,” “estimate,” “expects,” “goal,” “generate,” “guidance,” “integrate,” “maintain,” “objective,” “optimize,” “plan,” “project,” “target,” and similar expressions are intended to identify forward-looking statements. Forward-looking statements in this presentation include, among other things, the Company’s 2026 strategic objectives, operational plan and priorities, including: plans to successfully integrate the merger with Civitas Resources, Inc. (“Civitas” and the “Merger”); expectations regarding increased scale; expectations to action and realize synergies, including the timing and magnitude thereof; plans and expectations regarding portfolio optimization, deleveraging and stockholder returns; plans to maximize free cash flow and inventory value, increase liquidity, reduce debt, improve capital efficiency and strengthen the balance sheet and capital structure; plans to accelerate the Company’s return of capital program and allocate additional free cash flow to share repurchases; the Company’s expected allocation of free cash flow to its capital return program and future changes thereto; expectations regarding future leverage ratio and investment grade credit rating; the potential for future strategic asset sales to accelerate deleveraging; expectations regarding the Company’s $1 billion plus divestiture target and future divestiture opportunities; plans to fully redeem our Senior Notes due in 2027 (“2027 Senior Notes”); assumptions and projections for the third quarter, second half, and full year 2026 regarding guidance for total production; oil production; the Company’s capital plan, including total capital expenditures; drilling, completion and equipment costs; facility, land and other costs; one- time capital costs; Company average cost per lateral foot; expectations for full year 2026 activity by asset; certain operating expenses, including lease operating expense, transportation, production and ad valorem taxes; DD&A; general and administrative expense, and certain other costs, including exploration expense and cash taxes. These statements involve known and unknown risks, which may cause the Company's actual results to differ materially 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 the Company's most recent Annual Report on Form 10-K, as such risk factors may be updated from time to time in the Company's other periodic reports filed with the Securities and Exchange Commission, specifically the 2025 Form 10-K. The forward-looking statements contained herein speak as of the date of this presentation. Although the Company 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. Contacts Investor Relations Media Megan Hays, VP Investor Relations Meghan Dack, Director Investor Relations media@sm-energy.com mhays@sm-energy.com mdack@sm-energy.com
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3 2Q26 Key Messages EXECUTING WITH URGENCY, RETURNING CAPITAL TO STOCKHOLDERS 1 Generated record free cash flow from a scaled, growing platform $467MM of adjusted free cash flow1 and $1.4B of adjusted EBITDAX1 2 Accelerated Merger synergy capture Actioned 95% of $375MM synergy run-rate target; lowered FY26 G&A guidance by $50MM All synergies expected to be actioned by year-end 2026; 2027 captures full run-rate ($1.8B NPV-102) 3 Raised second-half production outlook; full-year capital reaffirmed Increased 2H26 total production outlook to 435-440 MBoe/d Maintained FY26 capital of $2.65–$2.85B 4 Substantially achieved $1B+ asset sale target Closed the $950MM South Texas (Galvan) sale; net proceeds directed to debt reduction SM’s increased scale creates a larger candidate set for future asset sales 5 Strengthened the balance sheet and returned capital to stockholders Clearing all maturities through mid-2028; path to low-1x leverage by year-end 2026, setting the stage for increased buybacks Returned $137MM (~30% of adjusted free cash flow1) to stockholders through share repurchases and dividend SM value creation flywheel: Operational excellence drives growing FCF , enabling asset optimization & accelerated deleveraging, with increasing stockholder returns – all working together to compound stockholder value 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2NPV of synergies represents PV-10 over 7 years.
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4 2Q26 Results Key Metric 2Q26 Guidance 2Q26 Actual vs. Guidance Total production (MBoe/d) 435─450 440 In range Oil production (MBbl/d) 228─235 230 In range Capital expenditures1 ($MM) $815─$855 $717 Below range Adjusted EBITDAX1 ($MM) ─ $1,406 Adjusted free cash flow1 ($MM) ─ $467 Adjusted net income1 (per diluted share) ─ $2.19 Stockholder returns2 ($MM) ─ $137 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2Stockholder returns include $84MM in share repurchases (2.6 million shares) and $0.22/share quarterly dividend. Operational & Financial Performance Highlights Record cash generation in first full quarter post- Merger: $467MM of adjusted free cash flow1 and $1.4B of adjusted EBITDAX,1 reflecting the earnings power of the combined portfolio Production: 2Q26 within guidance, 2H26 guidance increased; volumes growing sequentially throughout 2H26 Capital expenditures:1 2Q26 below the low end of guidance; FY26 capital guidance maintained Cash directed to debt reduction and stockholder returns: ~$1.1B net debt1 reduction, with ~30% returned to stockholders
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5 2026 Strategic Priorities STRUCTURALLY ENHANCING OUR VALUE PROPOSITION Leveraging our competitive advantages – operational scale, technical expertise, financial strength – to deliver consistent execution and stockholder value Capture the full value of the Merger Synergies on track to be fully actioned by year-end 2026 for full 2027 run-rate (~$1.8B NPV-101) INTEGRATE BOLSTEREXECUTE Execute on a capital-efficient platform Disciplined reinvestment driving durable free cash flow, anchored by an increased 2H26 production run-rate Strengthen our balance sheet and capital return engine Clear path to low-1x leverage by year-end 2026 and a return-of-capital framework that scales higher as we delever 1NPV of synergies represents PV-10 over 7 years.
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6 Integrate $375MM RUN -RATE SYNERGY TARGET NEARLY 2X ORIGINAL TARGET Integrate Execute Bolster Increasing & Accelerating Synergy Expectations ($MM) Highlights $355MM actioned, 95% of target achieved – full capture impact in 2027 Interest Savings: $75MM (100%) actioned Overhead / G&A: $100MM (100%) actioned D&C / Operations: $180MM (90%) actioned Simul-frac across Uinta and DJ basins (~$35MM) Permian program-level & frac-contract savings (~$30MM); water infrastructure optimization (~$25MM) LOE reductions (~$30MM) resulting from artificial lift optimization, reduced contract labor and crew optimization NPV-10 $1.8B1 All expected to be actioned by YE26 $30 $70 $100 $200 Interest Savings Overhead / G&A D&C / Operations Total Original Target Current Target $75 $375 $75 $100 $180 $355 Actioned (up from $300 prior quarter) 95% of $375MM target actioned $100 $200 Actioned 1NPV of synergies represents PV-10 over 7 years. 1 2 3
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7 Execute DELIVERING ON OUR NEW PLATFORM Integrate Execute Bolster Raising 2H26 Production Outlook1 Maintaining FY26 Capital Guidance1,2 Production Guidance Maximizing FCF2 Generation $2.75B DC&E $2.3–$2.5B Facilities, Land, & Other ~$280MM 1x Costs ~$70MM Capital Categories 1Refer to 2026 Guidance later in this deck. 2Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. Oil Production (MBbl/d) Total Production (MBoe/d) SM Value Creation Flywheel Growing FCF SM Value Creation Accelerated Deleveraging Increasing Returns to Stockholders Portfolio Optimization Operational Excellence 2H26 Prior 2H26 Run Rate 430 435–440 ~238 ~238
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8 Execute: Uinta Basin Value Capture OPERATIONAL INNOVATION COMPOUNDING INTO BETTER CAPITAL EFFICIENC Y Integrate Execute Bolster Stacked Completion Innovation Five completion innovations: 1 Simul-frac operations 2 Natural gas frac fleet 3 Remote frac equipment 4 Sand-slurry pipeline 5 Dual-string coil drillouts Faster flowback and facility optimization accelerates peak production, pulling cash flow forward: ~30-day IP acceleration Optimize facility capacity to increase throughput Fastback Flowback Completion Efficiency (ft/day) Long-Lateral Development Lowering Cost ($/ft) 1,000 1,200 1,000 1,700 2,100 2,300 2,600 Jan '26 Feb '26 Mar '26 Apr '26 May '26 Jun '26 Jul '26 Simul-frac transition >2x More efficient with simul-frac completions $800 $780 $740 10k' 15k' 20k' 4-mile development ~8% lower cost per foot on 4- mile laterals - more resource per location, less capital per unit >$1MM/well savings $200k/well NPV uplift Notes: Fastback NPV uplift at $75/Bbl WTI/$3.50/Mcf HH.
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9 Bolster STRENGTHENING OUR FINANCIAL POSITION Integrate Execute Bolster Rapid Debt Reduction 1Net debt is a non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2Illustrates the reduction in total Senior Notes principal outstanding since the Merger close, including the planned redemptio n of the 2027 Senior Notes. SM instructed the trustee to issue a notice of full redemption at par on August 5, 2026, with redemption expected on September 4, 2026. Agency Credit Rating / Outlook S&P BB / Stable Upgraded post Merger Fitch BB+ / Stable Upgraded post Merger Moody’s B1 / Positive Positive outlook post Merger Balance Sheet Transformation Supports Investment-Grade Trajectory Net debt¹ ~$6.3B, down ~$1.1B since 1Q26 Issued 6.625% notes due 2034 and retired higher-cost 8.375% notes due 2028, saving ~$16MM/yr in interest Redeemed all $819MM of 2026 Senior Notes using South Texas sale proceeds Redeeming the remaining $417MM of 2027 Senior Notes2 – no near-term maturities until mid-2028 Senior Notes Outstanding $7.6B $6.5B January 2026 Merger Close Post-2027 Note Redemption2 $1.1B debt reduction in 6 months Divestiture proceeds and free cash flow driving leverage ratio to low 1x
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10 Bolster SUBSTANTIALLY ACHIEVED $1B+ DIVESTITURE TARGET Integrate Execute Bolster A SUSTAINED VALUE CREATION LEVER – NOT A ONE-TIME EVENT Continuously high grade the portfolio SM’s increased scale creates a larger candidate set for accretive, non- core divestitures Accelerating SM value creation flywheel Divestiture proceeds accelerate debt reduction and create capacity for higher share buyback allocation South Texas – Maverick Basin Position Divested acreage $950MM South Texas Divestiture Sold non-core assets at attractive valuation Effective date February 1, 2026; closed April 30, 2026 Proceeds directed to gross debt reduction SM’s borrowing base and lender commitments reaffirmed following South Texas Divestiture – underscoring portfolio quality Forward Strategy: Active Portfolio Management
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11 Why Invest in SM Energy A SCALED, RETURNS -FOCUSED OPERATOR ENTERING A NEW PHASE OF VALUE CREATION SM is executing on a clear set of priorities: grow free cash flow, deleverage rapidly, and return increasing amounts of capital to stockholders to compound value Operational Excellence1 Growing Free Cash Flow2 Strategic Portfolio Optimization3 Accelerated Deleveraging4 Increasing Returns to Stockholders5 A Scaled SM A Stronger SM A More Valuable SM Premier multi-basin operator with ~736k net acres across Permian, DJ, South Texas, and Uinta ─ with high-quality inventory $950MM South Texas Divestiture; proceeds directed to debt reduction Record quarterly adjusted free cash flow2 of $467MM and $1.4B adjusted EBITDAX2 World-class technical team; proven execution and innovation Net debt2 down $1.1B since 1Q26; no maturities until mid-2028; path to low-1x leverage $137MM returned to stockholders (~30% of 2Q26 FCF); buybacks scaling as leverage declines $355MM synergies actioned (95% of synergy target), driving ~$1.8B NPV-101 Active portfolio management as a sustained lever ─ increased scale creates a larger candidate set for future high-grading and accretive asset sales 2H26 run-rate production increased; rising FCF generation sets the stage for a step-change in stockholder returns 1NPV of synergies represents PV-10 over 7 years. 2Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure.
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Guidance Asset Updates
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13 2026 Guidance Notes: Production 3Q26 FY26 Total Production (MMBoe)1 39.5 – 40.5 152.5 – 154.5 Total Production (MBoe/d)1 430 – 440 418 – 423 Oil Production (MBbl/d)1 230 – 240 223 – 225 Capital Program Capital Expenditures2 ($MM) $740 – $790 $2,650 – $2,850 DC&E $2,300 – $2,500 Facility, Land, and Other ~$280 One-Time Capital Costs3 ~$70 Net Wells Drilled ~55 ~245 Net Wells Turned-In-Line ~85 ~295 Avg. Well Cost ($/lateral ft)4 ~$710 Operating Expenses ($/Boe) Lease Operating Expense $6.50 – $6.80 Transportation $3.60 – $3.75 Production Taxes (% of oil, gas and NGL revenue) ~6% Ad Valorem Taxes ~$0.50 DD&A $14.00 – $15.00 General & Administrative ($MM) Recurring G&A5 $230 – $250 One-Time Integration & Transaction — Cash6 ~$160 One-Time Integration & Transaction — Non-Cash6 ~$20 Other ($MM) Exploration Expense ~$100 Cash Taxes: $75 – $80/Bbl (WTI) $20 – $30 $80 – $85/Bbl (WTI) $30 – $50 1. FY26 production guidance includes 11 months of Civitas contribution following the January 30, 2026, Merger close; the conversion of certain acquired volumes to two-stream reporting; and four months of production from the South Texas assets divested on April 30, 2026. Guidance for 2H26 production is 435–440 MBoe/d (~238 MBbl/d oil). 2. Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. FY26 capital expenditures before changes in accruals includes ~ $50 million of expected synergies. 3. Includes one-time, non-recurring capital costs related to Merger integration and the South Texas Divestiture. 4. Company-wide average 2026 expected well cost and includes well connection/equipment costs. 5. FY26 recurring G&A guidance includes ~$35 million of stock-based compensation. 6. The majority of one-time integration and transaction costs (both cash and non-cash) were incurred in 1H26. 7. Net drills, TILs and average lateral length based on operated and non-operated wells expected to be completed for FY26. Average rig and frac crew activity planned for FY26. FY26 Activity by Asset Basin Net Drills / TILs7 Avg. Well Lateral Ft.7 Avg. Rigs / Frac Crews7 Base PDP Decline Rate Capital Allocation (%) Permian Basin ~125 / ~150 ~11,300' 6 / 2 31% 45% DJ Basin ~55 / ~80 ~12,300' 1 / 1 34% 20% South Texas ~30 / ~35 ~12,600' 1.5 / 1 31% 15% Uinta Basin ~35 / ~30 ~16,500' 2.5 / 1 46% 20% Total ~245 / ~295 11 / 4.5 AS OF AUGUST 5, 2026
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14 ~99,000 NET ACRES Uinta Basin Oily, high-margin basin Innovative development of stacked pay DJ Basin ~301,000 NET ACRES Low-cost, high-margin basin Sustainability leader South Texas ~95,000 NET ACRES Liquids-rich core asset Repeatable results and upside runway Permian Basin ~241,0002 NET ACRES Scale in premier basin Cornerstone asset with high returns SM Energy – A Powerhouse in Shale PREMIER OPERATOR OF TOP -TIER ASSETS ACROSS THE HIGHEST -RETURN U. S. BASINS 2Q26 SM Profile Net Acres1, 2 as of June 2026 736k 2Q26 Total Production3 MBoe/d 440 2Q26 Oil Production3 MBbl/d 230 FY26 Avg. Rig Count 11 FY26 Avg. Frac Crews 4.5 1 Acreage presented excludes acreage outside of our core basins. 2 Includes ~ 8,000 net drill-to-earn acres. 3 Production volumes include only one month of production from the South Texas assets divested on April 30, 2026. Average daily production is calculated as total production for the quarter divided by 91 days.
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15 Executing Across the Portfolio 2Q26 ASSET HIGHLIGHTS Permian Basin ~241,000 net acres DJ Basin ~301,000 net acres South Texas ~95,000 net acres Divested acreage • 40 Net TILs • Improved drillout on extended laterals driving ~15% cost reduction2 • Advancing delineation across emerging development horizons SCALE CREATES THE EDGE; TECHNICAL TEAM AT WORK • 13 Net TILs • High-graded portfolio following South Texas Divestiture • Record set: drilled longest Austin Chalk well in Maverick Basin ~21,200’ • Completion efficiency +10% (ft/day)1 EFFICIENCY GAINS; HIGH-GRADED PORTFOLIO Uinta Basin ~99,000 net acres HIGH-VALUE OIL; LONGER WELLS; LOWER COST • 7 Net TILs • 2Q26 cash production margin ~$58/Boe – highest oil torque in portfolio • 14 four-mile laterals drilled YTD with state record set for deepest well • Optimized flowback strategy – pulling production forward CAPITAL EFFICIENCY IN ACTION; INFRASTRUCTURE DELIVERING • 12 Net TILs • Simul-frac efficiency gains compounding quarter-over- quarter • New central processing facility online – lower cost, faster TILs, smaller footprint 11H26 average vs. FY25 average. 21H26 average vs. cost expectations at the start of 2026.
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16 2Q26 KPIs by Asset Benchmark Pricing NYMEX WTI Oil ($/Bbl) $92.79 NYMEX Henry Hub Gas ($/MMBtu) $2.90 OPIS Composite NGL ($/Bbl) $31.33 Note: Amounts may not calculate due to rounding. 1 2Q26 figures include one month of contribution from certain South Texas assets sold on April 30, 2026 (~12 MBoe/d of quarter-average production and ~$20MM of capital). The sale included 10 net drilled-but- uncompleted wells. 2 Total production includes one month of South Texas contribution prior to the April 30, 2026, divestiture; see footnote 1 for divested-asset activity. 3 Non-GAAP measure. See the appendix for definition. Permian Basin DJ Basin South Texas1 Uinta Basin Total2Production Volumes Average Net Daily Production: Oil (MBbl/d) 126.7 54.8 13.9 34.4 229.8 Gas (MMcf/d) 551.3 260.4 107.9 34.1 953.7 NGLs (MBbl/d) 14.8 20.6 15.5 — 51.0 Equivalent (MBoe/d) 233.5 118.8 47.4 40.1 439.7 Total Net Production (MMBoe) 21.2 10.8 4.3 3.6 40.0 % Oil 54% 46% 29% 86% 52% Per Unit Metrics Realized Oil Price | $/Bbl $98.26 $97.62 $99.02 $89.65 $96.85 % of Benchmark – WTI 106% 105% 107% 97% 104% Realized Gas Price | $/Mcf ($1.05) $1.82 $1.96 $1.78 $0.17 % of Benchmark – NYMEX Henry Hub (36%) 63% 67% 62% 6% Realized NGL Price | $/Bbl $21.34 $26.60 $25.35 — $24.69 % of Benchmark – OPIS 68% 85% 81% — 79% Realized Price per Boe $52.22 $53.61 $41.77 $78.39 $53.86 LOE per Boe $8.26 $4.96 $3.70 $6.62 $6.71 Transportation per Boe $0.92 $6.38 $4.51 $9.65 $3.57 Production Tax per Boe $3.12 $3.96 $1.79 $3.47 $3.25 Production Tax as % of Pre-Hedge Revenue 6.0% 7.4% 4.3% 4.4% 6.0% Ad Valorem Tax per Boe $0.48 $0.10 $0.48 $0.37 $0.37 Cash Production Margin per Boe3 $39.44 $38.22 $31.30 $58.26 $39.96 Activity Net Drills 38 18 9 6 71 Net TILs 40 12 13 7 72
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Hedge Position Non-GAAP Definitions, Reconciliations, and Disclosures APPENDIX
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18 Strategic Risk Management HEDGE POSITION ~23,000 MBbls Hedged Weighted-average price of: $61.01/Bbl – $64.42/Bbl 2H26 Swaps & Collars Oil volumes1 Gas volumes3 ~84,800 BBtu Hedged Weighted-average price of: $3.69/MMBtu – $4.28/MMBtu 2H26 Basis Swaps Notes: Includes derivative contracts for settlement at any time during the third quarter of 2026 and later periods, entered into through July 24, 2026. 1Hedges include oil swaps and collars hedged to NYMEX WTI, excludes basis swaps, at a weighted-average price of $61.01/Bbl (collar floors and swaps) to $64.42/Bbl (collar ceilings and swaps). 2Percent of production hedged based on 2H26 total production and oil production guidance. 3Hedges include natural gas swaps and collars hedged to NYMEX Henry Hub and WAHA, excludes basis swaps, hedged to benchmark prices at a weighted-average price of $3.69/MMBtu (collar floors and swaps) to $4.28/MMBtu (collar ceilings and swaps). Basis Swaps Volumes Price Oil MBbls $/Bbl Midland Basin differential 2,100 $0.99 MEH differential 800 $1.99 Gas BBtu $/MMBtu WAHA differential 23,900 ($1.31) CIG Rockies differential 23,900 ($0.57) Hedged, 53%2 Hedged, 55%2
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19 Oil Derivative Positions NYMEX WTI NYMEX WTI Weighted-Average Price of Swaps and CollarsOil Swaps Oil Collars Period Volume (MBbls) $/Bbl2 Volume (MBbls) Floor $/Bbl2 Ceiling $/Bbl2 Floor Ceiling $/Bbl3 $/Bbl3 Q3 2026 6,398 $63.30 5,662 $59.51 $69.09 $61.52 $66.01 Q4 2026 7,673 $61.22 3,289 $58.66 $66.07 $60.45 $62.67 Q1 2027 5,440 $62.97 4,997 $59.12 $66.75 $61.12 $64.78 Q2 2027 3,077 $72.76 3,077 $66.67 $77.96 $69.71 $75.36 Q3 2027 2,047 $73.72 3,070 $66.67 $75.48 $69.49 $74.78 Q4 2027 989 $74.18 989 $65.00 $70.00 $69.59 $72.09 Midland - Cushing MEH – WTI NYMEX WTI Oil Basis Swaps Oil Basis Swaps Roll Basis Swaps Period Volume (MBbls) Price Differential $/Bbl2 Volume (MBbls) Price Differential $/Bbl2 Volume (MBbls) Price Differential $/Bbl2 Q3 2026 975 $0.99 392 $1.97 4,047 $0.59 Q4 2026 1,140 $0.99 378 $2.01 719 $1.08 Q1 2027 575 $1.02 — — — — Q2 2027 552 $1.02 — — — — Q3 2027 548 $1.02 — — — — Q4 2027 519 $1.02 — — — — 1Includes derivative contracts for settlement at any time during the third quarter of 2026 and later periods, entered into through July 24, 2026. 2Weighted-average contract price. 3Volume weighted-average contract price for NYMEX WTI swaps and NYMEX WTI collars. Oil1 Oil Basis1 OIL & OIL BASIS
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20 Gas and NGL Derivative Positions 1Includes derivative contracts for settlement at any time during the third quarter of 2026 and later periods, entered into through July 24, 2026. 2Weighted-average contract price. 3Volume weighted-average contract price for NYMEX Henry Hub swaps and collars and WAHA swaps. Gas1 NYMEX Henry Hub IF WAHA NYMEX Henry Hub Weighted-Average Price of Swaps and CollarsGas Swaps Gas Swaps Gas Collars Period Volume (BBtu) $/MMBtu2 Volume (BBtu) $/MMBtu2 Volume (BBtu) Floor $/MMBtu2 Ceiling $/MMBtu2 Floor $/MMBtu3 Ceiling $/MMBtu3 Q3 2026 16,937 $4.07 3,813 $2.35 21,905 $3.48 $4.33 $3.61 $4.05 Q4 2026 13,696 $4.30 1,067 $3.13 27,352 $3.53 $4.67 $3.77 $4.51 Q1 2027 16,398 $4.29 4,603 $3.64 9,661 $3.72 $4.86 $4.01 $4.37 Q2 2027 8,806 $3.65 — — 3,640 $3.73 $4.37 $3.67 $3.86 Q3 2027 7,352 $3.88 — — 3,680 $3.73 $4.37 $3.83 $4.05 Q4 2027 5,608 $4.04 — — 3,680 $3.73 $4.37 $3.91 $4.17 Gas Basis1 IF WAHA CIG Rockies Gas Basis Swaps Gas Basis Swaps Period Volume (BBtu) $/MMBtu2 Volume (BBtu) $/MMBtu2 Q3 2026 11,960 ($1.31) 11,960 ($0.57) Q4 2026 11,960 ($1.31) 11,960 ($0.57) Q1 2027 7,567 ($0.85) 1,800 ($0.37) Q2 2027 5,460 ($0.74) 1,820 ($0.37) Q3 2027 9,506 ($0.73) 1,840 ($0.37) Q4 2027 5,520 ($0.74) 1,840 ($0.37) NGLs1 Purity Ethane Swaps Period Volume (MBbls) $/Bbl2 Q3 2026 137 $11.71 Q4 2026 141 $11.71 GAS, GAS BASIS & NGLS
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21 Debt Maturity Schedule BALANCE SHEET AS OF AUGUST 5, 2026 Delivering on Our Debt Reduction Commitment 1Data as of August 5, 2026, unless otherwise noted. 2As announced on August 5, 2026, SM gave notice to redeem in full at par $417MM of 2027 Senior Notes. Debt Maturities1 ($MM) Revolving Credit Facility Senior Notes $5B Borrowing Base $2.5B Commitment Full Redemption in Progress2 $400 $- $417 $456 $750 $1,000 $1,350 $750 $750 $1,000 $- $500 $1,000 $1,500 $2,000 $2,500 2026 2027 2028 2029 2030 2031 2031 2032 2033 2034 UNDRAWN
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22 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 are presented below. These measures may not be comparable to similarly titled measures of other companies. Adjusted EBITDAX: Adjusted EBITDAX represents net income (loss) before interest expense, interest income, income taxes, depletion, depreciation, and amortization 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, non-recurring or one- time costs including transaction and integration costs associated with the Merger, 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 2026 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, including change in certain long-term items, less capital expenditures before changes in accruals. The Company uses this measure to represent the cash generated from operations, in excess of capital expenditures, that is available to fund discretionary uses such as debt reduction, stockholder returns, 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 or Adjusted EPS 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, gains and losses on divestitures, gains and losses on extinguishment of debt, non-recurring or one-time costs including transaction and integration costs associated with the Merger, 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. Cash production margin: Cash production margin is calculated as oil, gas, and NGL revenues (before the effects of commodity derivative settlements), less operating expenses (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. Capital expenditures: The Company’s operating plan guidance uses the term “capital expenditures,” which is defined to be before changes in accruals (excludes working capital), and is a non-GAAP measure. In reliance on the exception provided by Item 10(e)(1)(i)(B) of Regulation S-K, the Company is unable to provide a reconciliation of forward-looking non-GAAP capital expenditures because components of the calculations are inherently unpredictable, such as changes to, and the timing of, capital accruals, unknown future events, and estimating certain future GAAP measures. The inability to project certain components of the calculation could significantly affect the accuracy of a reconciliation.
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23 Non-GAAP Reconciliations Adjusted EBITDAX1 For the Three Months Ended For the Six Months Ended (in millions) June 30, 2026 Net income (GAAP) $ 1,071 $ 736 Interest expense 111 224 Income tax expense 318 243 Depletion, depreciation, and amortization 592 1,024 Exploration2 18 42 Stock-based compensation expense 7 17 Net derivative (gain) loss (272) 425 Net derivative settlement loss (220) (250) Gain on divestiture activity (262) (262) Transaction and integration costs3 37 172 Other, net 6 5 Adjusted EBITDAX (non-GAAP) $ 1,406 $ 2,376 Interest expense (111) (224) Income tax expense (318) (243) Exploration2 (18) (42) Amortization of deferred financing costs and debt premiums, net (5) (10) Transaction and integration costs3 (32) (152) Deferred income tax expense 316 231 Other, net (17) (44) Net change in working capital (118) (149) Net cash provided by operating activities (GAAP) $ 1,103 $ 1,743 Adjusted Net Income1 For the Three Months Ended For the Six Months Ended (in millions, except per share data) June 30, 2026 Net income (GAAP) $ 1,071 $ 736 Net derivative (gain) loss (272) 425 Net derivative settlement loss (220) (250) Gain on divestiture activity (262) (262) Transaction and integration costs3 37 172 Other, net 10 13 Tax effect of adjustments4 162 (22) Deferred tax remeasurement – corporate reorganization5 — 23 Adjusted net income (non-GAAP) $ 526 $ 835 Diluted net income per common share (GAAP) $ 4.46 $ 3.34 Net derivative (gain) loss (1.13) 1.93 Net derivative settlement loss (0.92) (1.14) Gain on divestiture activity (1.09) (1.19) Transaction and integration costs3 0.15 0.78 Other, net 0.04 0.07 Tax effect of adjustments4 0.68 (0.10) Deferred tax remeasurement – corporate reorganization5 — 0.10 Adjusted net income per diluted common share (non-GAAP) $ 2.19 $ 3.79 Basic weighted-average common shares outstanding 239 219 Diluted weighted-average common shares outstanding 240 220 1 Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 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 reconciliat ion above will vary from the amounts shown on the unaudited condensed consolidated statements of operations for the component of stock -based compensation expense recorded to exploration expense. 3 Transaction and integration costs include expenses associated with the Merger and post-Merger integration activities. For the three and six months ended June 30, 2026, these costs consisted of $ 37MM and $155MM, respectively, of one-time integration costs, (including $5MM and $20MM, respectively, of stock-based compensation), which were included in general and administrative expense in the accompanying statem ents of operations, and less than $1MM and $17MM, respectively, of one-time transaction costs included in other operating expense in the accompanying statements of operations. 4 The tax effect of adjustments was calculated using a tax rate of 22.9% for the three and six months ended June 30, 2026, and 22.1% for the three and six months ended June 30, 2025. These rates approximate the Company's statutory tax rates for the respective periods, as adjusted for ordinary permanent differences. 5 Reflects a non-recurring remeasurement of net deferred tax balances resulting from a change in state income tax apportionment du e to a corporate reorganization and the Merger.
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24 Non-GAAP Reconciliations Net Debt1 (in millions) As of June 30, 2026 Principal amount of Senior Notes2 $ 6,873 Revolving credit facility2 — Total principal amount of debt (GAAP) $ 6,873 Less: Cash and cash equivalents 620 Net debt (non-GAAP) $ 6,253 Adjusted Free Cash Flow1 (in millions) For the Three Months Ended For the Six Months Ended June 30, 2026 Net cash provided by operating activities (GAAP) $ 1,103 $ 1,743 Net change in working capital, including change in certain long-term items 81 133 Cash flow from operations before net change in working capital, including change in certain long-term items (non-GAAP) $ 1,184 $ 1,876 Capital expenditures (GAAP) $ 754 $ 1,309 Changes in capital expenditure accruals (37) 80 Capital expenditures before changes in accruals (non-GAAP) $ 717 $ 1,389 Adjusted free cash flow (non-GAAP) $ 467 $ 487 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2Amounts as of June 30, 2026, are from Note 6 – Long-Term Debt in Part I, Item 1 of the Company’s Form 10-Q. Note: Adjusted free cash flow includes one-time Merger integration and South Texas Divestiture cash costs of approximately $42MM ($32MM operating; $10MM capital) for 2Q26 and $222MM ($152MM operating; $70MM capital) year-to-date 2026.