Slides
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Third Quarter 2026 November 3, 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 strategic objectives, operational plan and priorities for 2026 and beyond, including: the substantial completion of the integration of the merger with Civitas Resources, Inc. (“Civitas” and the “Merger”) and expectations regarding continuous improvement and capital efficiency following integration; expectations regarding scale and portfolio focus; expectations to action and realize synergies, including the timing, magnitude, full capture in 2027 and estimated net present value 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; expectations regarding lowering corporate breakevens and capital intensity; expectations regarding service-cost inflation, including diesel and other consumables, and the Company’s ability to offset it through efficiencies and synergies; expectations regarding well productivity, cycle times, drilling and completion costs, the benefits of operational innovations such as simul-frac and extended-lateral development, and inventory quality and duration; expectations regarding sand supply and proppant cost savings by mid-2027; the Company’s return of capital program, including the expected allocation of free cash flow to share repurchases and the base dividend, the minimum percentage of post-dividend free cash flow allocated to share repurchases, and future changes thereto; expectations regarding future leverage ratio, including the Company’s path to low-1x leverage at mid-cycle commodity prices by year-end 2026; the redemption, repurchase or tender of senior notes, the expected debt maturity profile and expected interest savings; expectations regarding the Company’s $1 billion plus divestiture target and future divestiture opportunities; assumptions and projections for the fourth quarter 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 transaction, integration, and 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. 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 3Q26 Key Messages BUILDING A STRONGER, MORE DURABLE SM 1 Generated free cash flow and returned capital to stockholders • $397MM of adjusted free cash flow1 and $1.3B of adjusted EBITDAX1 • Returned $133MM (34% of adj. FCF1) through $81MM of share repurchases (24% of post-dividend adj. FCF1) and the dividend 2 Exceeded the Merger synergy target; structural cost base reset • Actioned ~$400MM vs. $375MM run-rate target (2x the original $200MM target) • Full run-rate captured in 2027; NPV-102 increased to $2.0B from $1.8B 3 3Q production within guidance; FY26 capital maintained at the midpoint, despite inflation • Narrowed FY26 capital to ~$2.75B; synergy capture and efficiencies help offset inflationary pressure 4 Strengthened the balance sheet • Net debt1 $6B, down from $7.4B at March 31 • Redeemed all $417MM of 2027 Senior Notes at par, clearing maturities through mid-2028 • Path to low-1x leverage at mid-cycle prices by year-end 2026 5 Substantially achieved $1B+ asset sale target • Closed the $950MM South Texas (Galvan) sale in 2026 • SM’s increased scale creates a larger candidate set for future asset sales 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2NPV of synergies represents PV-10 over 7 years. SM Value Creation Flywheel: Operational excellence drives growing FCF , enabling asset optimization & accelerated deleveraging, with increasing stockholder returns – all working together to compound stockholder value
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4 3Q26 Results Key Metric 3Q26 Guidance 3Q26 Actual vs. Guidance Total production (MBoe/d) 430─440 433 In range Oil production (MBbl/d) 230─240 230 In range Capital expenditures1 ($MM) $740─$790 $747 In range Adjusted EBITDAX1 ($MM) ─ $1,341 Adjusted free cash flow1 ($MM) ─ $397 Adjusted net income1 (per diluted share) ─ $1.95 Stockholder returns2 ($MM) ─ $133 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2Stockholder returns include $81MM in share repurchases (2.3MM shares) and $52MM in dividends ($0.22/share). Operational & Financial Performance Highlights Cash generation: $1.1B of operating cash flow, $397MM of adjusted free cash flow1 and $1.3B of adjusted EBITDAX1 Production: Within guidance; oil impacted by ~2 MBbl/d of Permian downtime for compliance and safety work on acquired assets, now resolved, and ~4 MBbl/d of temporary Uinta takeaway constraints expected to be resolved with added capacity in early 2027 Capital expenditures:1 Within guidance; FY26 capital narrowed to ~$2.75B (prior midpoint), with synergies and efficiencies offsetting inflation Cash directed to debt reduction and stockholder returns: Redeemed $417MM of 2027 Senior Notes; returned ~34% of adjusted free cash flow1,2 to stockholders
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5 2026: Transformation on Track INTEGRATION RESET COMBINED PLATFORM; NEXT PHASE COMPOUNDS THE AD VANTAGES OBJECTIVE TARGET OUTCOME Synergies $200MM original, raised to $375MM ~$400MM actioned, 2x original target Divestitures $1B+ within 1 year ~$950MM South Texas sale Leverage Low-1x at mid-cycle prices On track for low-1x by year-end 2026 Net debt1 $7.4B at 1Q26 $6B at 3Q26, ~$85MM annualized interest savings Capital return 80/20 post-dividend FCF1: debt reduction / repurchases $165MM YTD share repurchases; $1.3B net debt1 reduction since 1Q26 Capital $2.65–$2.85B Held at $2.75B through inflation Integration Key workstreams substantially complete; acquired assets on SM systems and standards 2026: DELIVERED NEXT PHASE: Execute with greater capital efficiency: lower program breakeven price Deepen inventory quality and duration: Woodford-Barnett and Uinta delineation; disciplined ground game Maintain the balance sheet at low-1x leverage at mid-cycle prices Increase capital returns to stockholders COMPOUNDING THE ADVANTAGES 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure.
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6 Integrate: Merger Synergies Exceeded $400MM ACTIONED VS. $200MM ORIGINAL TARGET Integrate Execute Bolster Cost of Capital LOWER INTEREST COST S G&A A MORE EFFICIENT ORGANIZATION D&C / Operations CAPITAL HELD THROUGH INFLATION BEFORE ~$3B of senior notes due within 3 years $280 – $300MM recurring G&A (initial FY26 guidance) $2.65 – $2.85B budgeted $2.50/gal diesel (initial FY26 guidance) AFTER ~$2.1B near-term retired $1.1B net decrease; no maturities until mid-2028 $85MM annualized interest savings $230 – $250MM recurring G&A >25% lower vs. pro forma FY25 ~$2.75B FY26 capital held at midpoint despite diesel >2x budget ~8% industry D&C inflation in 20261 $400MM ACTIONED LOWER STRUCTURAL COST BASE ENTERING 2027 1Rystad Energy, Service Price Inflation: Shale, 4Q 2026 (Oct. 21, 2026), p. 11: US L48 drilling and completions costs (base ca se), quarter-over-quarter percent change. ~8% = average of 1Q26–4Q26 cost levels vs. 4Q25, compounding QoQ changes of 1%, 6%, 4% and 2%.
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7 Execute EFFICIENCY GAINS SUPPORT CAPITAL DISCIPLINE Integrate Execute Bolster 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. 3Cycle time is defined as the average number of days from spud to first sales. Holding FY26 Capital at Midpoint1,2 ~$2.75B FY26 CAPITAL MIDPOINT DC&E ~$2.4B Facilities, Land, & Other ~$280MM 1x Costs ~$70MM Capital Categories Company-Wide Avg. Cycle Times3 (# Days) 215 205 185 1Q26 2Q26 3Q26 Company-wide cycle times ↓ ~14% 1Q26 to 3Q26 Faster cycle times and operating efficiencies offsetting inflationary pressures.
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8 Execute: Delaware Basin Well Productivity IMPROV ING OIL PRODUCTIVITY Integrate Execute Bolster Source: Internal data as of October 2026. Cumulative oil production normalized per foot of lateral, measured at 180 days of production based on daily production data. Delaware Basin wells by turn-in- line vintage; 2026 reflects 21 wells placed on production year-to-date that have reached 180 days. 6-Month Cumulative Oil per Lateral Foot 10.1 11.4 14.1 0 2 4 6 8 10 12 14 0 1 2 3 4 5 6 Cumulative Oil (Bbl/ft) Months on Production Higher well productivity and faster drilling are improving Delaware Basin capital efficiency. 2026 wells 2025 wells 2024 wells 1,560 ft/day Drilling speed in 3Q, 9% above 2025 ~40% more cumulative oil per lateral foot at 180 days, 2026 vs. 2024 +13% 2024 → 2025 10.1 → 11.4 Bbl/ft +24% 2025 → 2026 11.4→ 14.1 Bbl/ft
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9 1,000 1,200 1,000 1,700 2,100 2,300 2,600 2,300 2,800 Jan '26 Feb '26 Mar '26 Apr '26 May '26 Jun '26 Jul '26 Aug '26 Sep '26 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) Simul-frac transition >2x more efficient with simul-frac completions >$1MM/well savings $200k/well NPV uplift Notes: Fastback NPV uplift at $75/Bbl WTI/$3.50/Mcf HH.
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10 STRENGTHENING OUR FINANCIAL POSITION Integrate Execute Bolster Bolster Senior notes down ~$1.1B since merger close • Redeemed $819MM of 2026 and $417MM of 2027 senior notes • Tendered $894MM of 8.375% 2028 notes Interest savings stacking up ~$85MM in annualized savings actioned in ~9 months Lower leverage provides a stronger, more resilient balance sheet Data as of November 3, 2026, unless otherwise noted. Senior Notes Reduced by $1.1B Since Merger Close $856 $750 $1,000 $1,350 $750 $750 $1,000 2026 2027 2028 2029 2030 2031 2031 2032 2033 2034 Remaining New 2034 notes Redeemed to date $5B Borrowing Base $2.5B Commitment Undrawn Revolving Credit Facility NO SENIOR NOTE MATURITIES THROUGH MID-2028 ON PATH TO LOW-1X LEVERAGE BY YEAR-END 2026
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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 to compound through-cycle per-share value: invest in high-return projects, generate free cash flow, maintain a strong balance sheet, and return capital to stockholders Operational Excellence1 Capital Efficiency & Free Cash Flow2 Inventory Quality & Duration3 Accelerated Deleveraging4 Durable Capital Returns5 A Scaled SM A Stronger SM A More Valuable SM Premier multi-basin operator with ~732k net acres across Permian, DJ, South Texas, and Uinta ─ with high-quality inventory $950MM South Texas Divestiture; proceeds directed to debt reduction Quarterly adjusted free cash flow1 of $397MM and $1.3B adjusted EBITDAX1 Experienced technical team; proven execution and innovation; ongoing Woodford-Barnett and Uinta delineation; disciplined ground game Net debt1 down $1.3B since 1Q26; no maturities until mid-2028; path to low-1x leverage at mid-cycle prices by year-end 2026 $133MM returned to stockholders (~34% of 3Q26 adj. FCF1); buybacks scaling as leverage declines $400MM synergies actioned (2x original target), driving ~$2.0B NPV-102 Active portfolio management ─ increased scale creates a larger candidate set for future high-grading and accretive asset sales Disciplined capital, durable returns: capital competes for the highest risk-adjusted returns, with free cash flow and capital efficiency prioritized over volume 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2NPV of synergies represents PV-10 over 7 years.
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Guidance Asset Updates
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13 2026 Guidance Notes: Production 4Q26 FY26 Total Production (MMBoe)1 40 – 41 153 – 154 Total Production (MBoe/d)1 435 – 445 420 – 422 Oil Production (MBbl/d)1 229 – 239 220 – 222 Capital Program Capital Expenditures2 ($MM) ~$610 ~$2,750 DC&E ~$2,400 Facility, Land, and Other ~$280 One-Time Capital Costs3 ~$70 Net Wells Drilled ~55 ~245 Net Wells Turned-In-Line ~80 ~295 Avg. Well Cost ($/lateral ft)4 ~$710 Operating Expenses ($/Boe) Lease Operating Expense $6.60 – $6.80 Transportation $3.55 – $3.65 Production Taxes (% of oil, gas and NGL revenue) ~6% Ad Valorem Taxes ~$0.50 DD&A ~$14.50 General & Administrative ($MM) Recurring G&A5 $230 – $250 One-Time Transaction & Integration — Cash6 ~$160 One-Time Transaction & Integration — Non-Cash6 ~$20 Other ($MM) Exploration Expense ~$100 Cash Taxes $100 – $120 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 Galvan assets divested on April 30, 2026. 4Q26 guidance includes the continued impact of Uinta takeaway constraints, which are expected to be resolved in early 2027. 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, including well connection/equipment costs. 5. FY26 recurring G&A guidance includes ~$35 million of stock-based compensation. 4Q26 recurring G&A is expected to be higher quarter over quarter due to year-end items. 6. The majority of one-time transaction and integration 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 in FY26. Average rig and frac crew activity planned in 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 NOVEMBER 3, 2026
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14 ~99,000 NET ACRES Uinta Basin Oily, high-margin basin Innovative development of stacked pay DJ Basin ~300,000 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 ~238,0002 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 3Q26 SM Profile Net Acres1, 2 as of September 2026 732k 3Q26 Total Production MBoe/d 433 3Q26 Oil Production 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.
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15 Executing Across the Portfolio 3Q26 ASSET HIGHLIGHTS Permian Basin ~238,000 net acres DJ Basin ~300,000 net acres South Texas ~95,000 net acres • 35 Net TILs • Delaware Basin well productivity increasing: +13% in 2025, +24% in 2026, and ~40% above 20241 • Woodford-Barnett: 8 wells online in 2026, tracking above area average cumulative oil per foot SCALE CREATES THE EDGE; TECHNICAL TEAM AT WORK • 5 Net TILs • Drilling efficiency +22% and completion efficiency +18% (ft/day)2 HIGH-GRADED PORTFOLIO; EFFICIENCY GAINS Uinta Basin ~99,000 net acres HIGH-VALUE OIL; LONGER WELLS; LOWER COST • 11 Net TILs • First SM-designed pad online: longer laterals, optimized spacing, enhanced completions, and results tracking above prior wells • First 4-mile wells successfully drilled out, turning in line in 4Q • Completion cost per lateral foot down ~16% since 1Q, to ~$400/foot CAPITAL EFFICIENCY IN ACTION; INFRASTRUCTURE DELIVERING • 24 Net TILs • Lowest well cost ($/lateral foot) in the portfolio • Local sand mine investment expected to supply all sand needs and lower proppant cost by ~40% vs. in-basin market, by mid-2027 1 Cumulative oil production normalized per foot of lateral, measured at 180 days of production based on daily production data. Delaware Basin wells by turn-in-line vintage; 2026 reflects wells placed on production year-to-date that have reached 180 days. 2 3Q26 vs. FY25 average.
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16 3Q26 KPIs by Asset Benchmark Pricing NYMEX WTI Oil ($/Bbl) $85.79 NYMEX Henry Hub Gas ($/MMBtu) $2.95 OPIS Composite NGL ($/Bbl) $31.64 Permian Basin DJ Basin South Texas Uinta Basin TotalProduction Volumes Average Net Daily Production: Oil (MBbl/d) 118.9 56.9 16.5 37.9 230.2 Gas (MMcf/d) 546.8 246.5 83.0 40.6 917.0 NGLs (MBbl/d) 12.7 21.4 15.9 nm 50.1 Equivalent (MBoe/d) 222.7 119.4 46.3 44.7 433.1 Total Net Production (MMBoe) 20.5 11.0 4.3 4.1 39.8 % Oil 53% 48% 36% 85% 53% Per Unit Metrics Realized Oil Price | $/Bbl $86.42 $87.89 $83.65 $81.44 $85.76 % of Benchmark – WTI 101% 102% 98% 95% 100% Realized Gas Price | $/Mcf $2.44 $2.66 $2.27 $2.33 $2.48 % of Benchmark – NYMEX Henry Hub 83% 90% 77% 79% 84% Realized NGL Price | $/Bbl $30.46 $30.25 $27.41 nm $29.40 % of Benchmark – OPIS 96% 96% 87% nm 93% Realized Price per Boe $53.86 $52.78 $43.35 $71.21 $54.23 LOE per Boe $8.94 $4.74 $4.45 $6.42 $7.02 Transportation per Boe $0.71 $5.70 $4.18 $11.17 $3.53 Production Tax per Boe $3.17 $4.59 $2.11 $3.41 $3.47 Production Tax as % of Pre-Hedge Revenue 5.9% 8.7% 4.9% 4.8% 6.4% Ad Valorem Tax per Boe $0.46 $0.25 $0.38 $0.34 $0.38 Cash Production Margin per Boe1 $40.58 $37.50 $32.23 $49.87 $39.83 Activity Net Drills 30 8 7 8 53 Net TILs 35 24 5 11 75 Note: Amounts may not calculate due to rounding. 1 Non-GAAP measure. See the appendix for definition.
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17 $215MM vs. $200MM target ($100MM original) TARGET EXCEEDED • Completion design and frac contracting across the Permian and Uinta basins (~$45MM) • LOE reductions (~$45MM) • Simul-frac in Uinta and DJ basins (~$35MM) Merger Synergies Recap $400MM RUN -RATE SYNERGIES ACTIONED 2X THE ORIGINAL TARGET 1NPV of synergies represents PV-10 over 7 years. $85MM vs. $75MM target ($30MM original) TARGET EXCEEDED • Maturities inside three years reduced by $2.1B • $85MM of annual interest savings in the run rate • On path to low-1x leverage at mid- cycle prices by year-end 2026 Cost of Capital LOWER INTEREST COSTS G&A A LEANER ORGANIZATION D&C / Operations A MORE EFFICIENT OPERATING MODEL $100MM vs. $100MM target ($70MM original) TARGET MET • One organization, one set of systems • Eliminated duplicate public company costs • Lowered FY26 recurring G&A guidance by $50MM in August; 3Q run rate $52MM $400MM ACTIONED $200MM ORIGINAL TARGET $2.0B NPV-101
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Hedge Position Non-GAAP Definitions, Reconciliations, and Disclosures APPENDIX
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19 Strategic Risk Management HEDGE POSITION ~11,000 MBbls Hedged Weighted-average price of: $60.45/Bbl – $62.67/Bbl 4Q26 Swaps & Collars Oil volumes1 Gas volumes3 ~42,100 BBtu Hedged Weighted-average price of: $3.77/MMBtu – $4.51/MMBtu 4Q26 Basis Swaps Notes: Includes derivative contracts for settlement at any time during the fourth quarter of 2026, entered into through October 23, 2026. 1Hedges include oil swaps and collars hedged to NYMEX WTI, excludes basis swaps, at a weighted-average price of $60.45/Bbl (collar floors and swaps) to $62.67/Bbl (collar ceilings and swaps). 2Percent of production hedged based on 4Q26 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 $3.77/MMBtu (collar floors and swaps) to $4.51/MMBtu (collar ceilings and swaps). Basis Swaps Volumes Price Oil MBbls $/Bbl Midland Basin differential 1,140 $0.99 MEH differential 378 $2.01 Gas BBtu $/MMBtu WAHA differential 11,960 ($1.31) CIG Rockies differential 11,960 ($0.57) Hedged, 51%2 Hedged, 50%2
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20 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 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 4,094 $67.50 $75.61 $69.57 $74.98 Q4 2027 3,088 $74.06 2,099 $67.64 $75.19 $71.46 $74.52 Q1 2028 2,106 $75.36 — — — $75.36 $75.36 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 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 fourth quarter of 2026 and later periods, entered into through October 23, 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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21 Gas and NGL Derivative Positions 1Includes derivative contracts for settlement at any time during the fourth quarter of 2026 and later periods, entered into through October 23, 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 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 10,744 $3.66 — — 3,680 $3.73 $4.37 $3.68 $3.84 Q4 2027 5,608 $4.04 — — 3,680 $3.73 $4.37 $3.91 $4.17 Q1 2028 3,259 $4.05 — — — — — $4.05 $4.05 Q2 2028 — — 7,280 $1.11 — — — $1.11 $1.11 Gas Basis1 IF WAHA CIG Rockies Gas Basis Swaps Gas Basis Swaps Period Volume (BBtu) $/MMBtu2 Volume (BBtu) $/MMBtu2 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 Q4 2026 141 $11.71 GAS, GAS BASIS & NGLS
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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 third 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 Nine Months Ended (in millions) September 30, 2026 Net income (GAAP) $ 93 $ 829 Interest expense 116 340 Income tax expense 30 273 Depletion, depreciation, and amortization 590 1,614 Exploration2 20 62 Stock-based compensation expense3 13 30 Net derivative loss 684 1,109 Net derivative settlement loss (207) (457) (Gain) loss on divestiture activity 2 (260) Transaction and integration costs4 5 177 Other, net (5) — Adjusted EBITDAX (non-GAAP) $ 1,341 $ 3,717 Interest expense (116) (340) Income tax expense (30) (273) Exploration2 (20) (62) Amortization of deferred financing costs and debt premiums, net (6) (16) Transaction and integration costs4 (5) (157) Deferred income tax expense (benefit) (7) 224 Other, net 26 (18) Net change in working capital (61) (210) Net cash provided by operating activities (GAAP) $ 1,122 $ 2,865 Adjusted Net Income1 For the Three Months Ended For the Nine Months Ended (in millions, except per share data) September 30, 2026 Net income (GAAP) $ 93 $ 829 Net derivative loss 684 1,109 Net derivative settlement loss (207) (457) (Gain) loss on divestiture activity 2 (260) Transaction and integration costs4 5 177 Other, net (1) 12 Tax effect of adjustments5 (111) (133) Deferred tax remeasurement – corporate reorganization6 — 23 Adjusted net income (non-GAAP) $ 465 $ 1,300 Diluted net income per common share (GAAP) $ 0.39 $ 3.66 Net derivative loss 2.86 4.90 Net derivative settlement loss (0.87) (2.02) (Gain) loss on divestiture activity 0.01 (1.15) Transaction and integration costs4 0.02 0.78 Other, net — 0.06 Tax effect of adjustments5 (0.46) (0.59) Deferred tax remeasurement – corporate reorganization6 — 0.10 Adjusted net income per diluted common share (non-GAAP) $ 1.95 $ 5.74 Basic weighted-average common shares outstanding 237 225 Diluted weighted-average common shares outstanding 239 226 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 unaud ited condensed consolidated statements of operations. Therefore, the exploration line items shown in the reconciliation above wi ll 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 For the three and nine months ended September 30, 2026, the stock -based compensation expense line item in the reconciliation ab ove differs from the amount shown in the unaudited condensed consolidated statements of cash flows because it excludes stock-based compensation expense included within the transaction and integration costs line item above. 4 Transaction and integration costs include expenses associated with the Merger and post -Merger integration activities. For the three and nine months ended September 30, 2026, these costs consisted of $4 million and $159 million, respectively, of one-time integration costs (including less than $1 million and $20 million, respectively, of stock-based compensation), which were included in general and administrative expense in the unaudited condensed consolidated statements of operations, and $1 million and $18 million, respectively, of one- time transaction costs included in other operating expense in the unaudited condensed consolidated statements of operations. 5 The tax effect of adjustments was calculated using a tax rate of 22.9% for the three and nine months ended September 30, 2026 . This rate approximates the Company's statutory tax rates for the periods presented, as adjusted for ordinary permanent differe nces. 6 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 September 30, 2026 Principal amount of Senior Notes2 $ 6,456 Revolving credit facility2 — Total principal amount of debt (GAAP) $ 6,456 Less: Cash and cash equivalents 442 Net debt (non-GAAP) $ 6,014 Adjusted Free Cash Flow1 (in millions) For the Three Months Ended For the Nine Months Ended September 30, 2026 Net cash provided by operating activities (GAAP) $ 1,122 $ 2,865 Net change in working capital, including change in certain long-term items 22 155 Cash flow from operations before net change in working capital, including change in certain long-term items (non-GAAP) $ 1,144 $ 3,020 Capital expenditures (GAAP) $ 711 $ 2,020 Changes in capital expenditure accruals 36 116 Capital expenditures before changes in accruals (non-GAAP) $ 747 $ 2,136 Adjusted free cash flow (non-GAAP) $ 397 $ 884 1Non-GAAP measure. See the appendix for definitions and reconciliations to the most directly comparable GAAP measure. 2Amounts as of September 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, non-recurring Merger integration cash costs of approximately $5MM for 3Q26 (operating), and Merger integration and South Texas Divestiture cash costs of $227MM YTD ($157MM operating; $70MM capital).