Slides
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Investor Presentation Februar y 2026
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GPOR | 2 Forward Looking Statements & Non-GAAP Financial Measures This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act, Section 21E of the Exchange Act, and the Private Securities Litigation Reform Act of 1995, that are subject to risks and uncertainties. These statements involve known and unknown risks, uncertainties and other factors that may cause our actua l results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements by terms such as “may,” “will,” “should,” “could,” “would,” “expects,” “plans,” “anticipates,” “intends,” “believes,” “estimates,” “projects,” “predicts,” “potential” and similar expressions intended to identify forward -looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that we expect or anticipate will or may occur in the future, including estimated future production and net revenues from oil and gas reserves and the present value thereof, future capital expenditures (including the amount and nature thereof), share repurchases, business strategy and measures to implement strate gy, competitive strength, goals, expansion and growth of our business and operations, plans, references to future success, reference to intentions as to future matters and other such matters are forward-looking statements. These forward-looking statements are largely based on our expectations and beliefs concerning future events, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors relating to our operations and business environment, all of which are difficult to predict and many of which are beyond our control. Although we believe our estimate s and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccura te. Management cautions all readers that the forward-looking statements contained in this presentation are not guarantees of future performance, and we cannot assure any reader that those statements will be realized or the forwa rd-looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors listed in Item 1A. “Risk Factors” and Item 7. “Manag ement’s Discussion and Analysis of Financial Condition and Results of Operations” in Gulfport’s Annual Report on Form 10-K for the year ended December 31, 2025, Item 2. “Management’s Discussion and Analysis of Financial Condition a nd Results of Operations” in Gulfport’s Quarterly Reports on Form 10-Q and all forward-looking statements speak only as of the date of this presentation. Gulfport’s proved reserves and adjusted proved reserves are those quantities of natural gas, oil, and natural gas liquids, wh ich, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating meth ods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabil istic methods are used for the estimation. Gulfport’s estimate of its total proved reserves are internally generated and audited by Netherland, Sewell Associates, Inc., independent petroleum engineers. Factors affecting ultimate recovery include the scope of Gulfport’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, avai lability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals, actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. Estimates may change significantly as development of Gulfport’s natural gas, oil and natural gas liquids assets provide additional data. Gulfport’s production forecasts and expectations for future periods are dependent upon many assumpti ons, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases . Gulfport’s management uses certain non-GAAP financial measures for planning, forecasting and evaluating business and financial p erformance, and believes that they are useful tools to assess Gulfport’s operating results. Although these are not measures of performance calculated in accordance with generally accepted accounting principles (GAAP), manageme nt believes that these financial measures are useful to an investor in evaluating Gulfport because ( i) analysts utilize these metrics when evaluating company performance and have requested this information as of a recent practic able date, (ii) these metrics are widely used to evaluate a company’s operating performance, and (iii) we want to provide updated information to investors. Investors should not view these metrics as a substitute for measures of per formance that are calculated in accordance with GAAP. In addition, because all companies do not calculate these measures identically, these measures may not be comparable to similarly titled measures of other companies. T hese non-GAAP financial measures include adjusted EBITDA, adjusted free cash flow, recurring general and administrative expense and present value of estimated future net revenue. A reconciliation of each financial measure to i ts most directly comparable GAAP financial measure is included as part of this presentation. These non - GAAP measures should be considered in addition to, but not instead of, the financial statements prepared in accordance with G AAP.
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GPOR | 3 ~75% ~ 15% ~ 10% Utica Marcellus SCOOP 2026E Activity Gulfport Energy Overview 1. Market capitalization calculated as of 2/19/26 at a price of $201.56 per share using shares outstanding from the Company’s 2025 10-K filing. 2. Enterprise value calculated as of 2/19/26 at a price of $201.56 per share using shares outstanding, long-term debt and cash and cash equivalents from the Company’s 2025 10-K financial statements. 3. As of 12/31/25 and calculated as $1.8 million cash plus $804.3 million borrowing base availability, which takes into effect $147.0 million of borrowings on revolver and $48.7 million of letters of credit. 4. As of 12/31/25 using net debt to LTM Adjusted EBITDA. Net debt and Adjusted EBITDA are non-GAAP measures. Net debt is defined as total long-term debt minus cash and cash equivalents. 5. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Adjusted free cash flow excludes discretionary acreage acquisitions and common stock repurchases. Adjusted free cash flow yield is calculated using adjusted free cash flow divided by market capitalization using shares outstanding from the Company’s 2025 10-K filing. 6. Appalachia acreage includes ~223,000 Utica and ~35,000 Marcellus net reservoir acres. SCOOP acreage includes ~44,000 Woodford and ~30,000 Springer net reservoir acres. 7. EBITDA estimate sourced from Factset as of 2/19/26. Utica and Marcellus YE25 Net Reservoir Acres(6): ~258,000 YE25 Proved Reserves: 3.3 Net T cfe 4Q25 Net Production: ~915 MMcfe/day SCOOP YE25 Net Reservoir Acres(6): ~74,000 YE25 Proved Reserves: 0.9 Net T cfe 4Q25 Net Production: ~183 MMcfe/day Key Highlights NYSE: GPOR Market Cap(1): $3.7 Billion Enterprise Value (‘EV’)(2): $4.5 Billion EV / 2026 EBITDA(2,7): 4.8x Liquidity(3): ~$806 Million Leverage(4): ~0.9x Operated D&C Capital: $365 – $390 Million Maintenance Land & Seismic Capital: $35 – $40 Million 2026E T otal Operated Capital: $400 – $430 Million 2026E T otal Net Equivalent Production: 1.030 – 1.055 Bcfe/day Expect total net production to increase ~5% in 4Q2026 versus 4Q2025 Top-decile adjusted free cash flow yield(5) relative to natural gas peers Remaining Inventory: >700 gross operated ~15 years of net inventory at attractive rates of return ~ 85% ~ 15% Utica / Marcellus SCOOP 2026E Production Mix2026E Operated D&C Capital
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GPOR | 4 Focused Strategy and Compelling Valuation 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. High Quality Asset Base Natural Gas Weighted with Liquids Opportunities • Multi-basin portfolio provides diversification and capital allocation optionality • Capture value accretion through significant expansion of undeveloped inventory, driven by targeted discretionary acreage acquisitions, Marcellus delineation and U-development initiatives • Low breakeven inventory supports sustainable returns and adjusted free cash flow(1) generation Committed to Responsible Stewardship • Achieved overall “A” rating for Appalachia assets from MiQ for third consecutive year • Safety of employees, contractors and communities is our highest priority • Provide community support through giving and volunteering in our operating areas Improve Margins and Free Cash Flow Generation Enhance Shareholder Value through Disciplined Capital Allocation Maintain Strong Balance Sheet • Focus on continuously improving cycle times and reducing operating costs • T op decile adjusted free cash flow(1) yield and positive adjusted free cash flow(1) across wide range of commodity prices • Maintain financial strength and flexibility to execute strategic and operating plans in volatile commodity environment • Hedging program reduces commodity risk and future cash flow volatility • Consistent shareholder return framework returning capital to shareholders through repurchase of undervalued equity • Reinvest in strategic acquisition opportunities that provide operating synergies, quality resource depth and optionality to our near-term development activities
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GPOR | 5 2023 2024 2025 $3.50 $3.75 $4.00 4.25 ($ MM) Completed Available Delivering Value For Shareholders Equity Repurchase Program $1.5 Billion Stock Repurchase Authorization ~$580 million Available under increased authorization ~$920 million Repurchased as of December 31, 2025, retiring ~7.4 million shares(4) at an average price of $125.19 per share 2026E Adjusted Free Cash Flow Generation(1,5) • Consistent shareholder return framework and equity repurchase program authorizes purchases up to $1.5 billion • Adjusted free cash flow(1) generation estimated to increase >40%(6) during 2026 compared to FY 2025 • Expect to maintain an active repurchase program through 2026, supported by adjusted free cash flow(1) (excluding discretionary acreage acquisitions) and revolver capacity with leverage maintained at approximately 1.0x or below • Plan to repurchase more than $140 million of common stock in 1Q2026 Equity Repurchases 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions an d common stock repurchases. 2. Includes $18.4 million to satisfy tax withholding requirements incurred upon vesting of initial emergence performance stock u nits granted to certain executive officers in 2021. 3. Includes $12.3 million of cash utilized to settle performance stock units that were granted to certain executive officers in 2022. 4. Includes redemption of preferred equity totaling $31.3 million for ~180,000 shares of common stock on an as -converted basis based on redemption price of $174.22. 5. 2026E FCF sensitivities based upon flat price cases and does not assume changes in cost structure or activity levels at diffe rent commodity prices. Includes current hedge position as of 2/19/26. 6. Based on $4.00 NYMEX / $65 WTI flat price case referenced above. Return of Capital ($MM) FY 2023 FY 2024 FY 2025 Annual adjusted free cash flow(1) $199 $257 $325 Less: discretionary acreage acquisitions ($48) ($45) ($63) Less: equity repurchases executed ($149) ($203)(2) ($349)(3,4) Remaining adjusted free cash flow(1) available $2 $9 ($87) % of adjusted free cash flow returned to shareholders 99% 96% 100%+ Year-end leverage 0.98x 0.97x 0.90x 2026E Adjusted Free Cash Flow >25% growth Y-o-Y >40% growth Y-o-Y >55% growth Y-o-Y $4.25 Gas / $65.00 Oil >10% growth Y-o-Y $4.00 Gas / $65.00 Oil $3.75 Gas / $65.00 Oil $3.50 Gas / $65.00 OilGas $2.74 $2.27 $3.43 Oil $77.61 $75.72 $64.77 FY 2026 (as of 2/19/26) Gas $3.86 Oil $64.19
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GPOR | 6 Base Assumptions (2026E Guidance) Upside Potential Net Production: Low single digit growth of 0% – 5% Improving base decline, reduced cycle times, and potential uplift from deferred production associated with known downtime Cash Costs: $1.35 – $1.48 / Mcfe Reducing per unit cash costs which includes LOE, GP&T, taxes other than income and G&A T otal Capital: $365 – $390MM Operated D&C $35MM Maintenance Land Continued efficiencies, cost reductions and lower maintenance capital spend Differentials: Natural Gas: $0.15 - $0.30 off NYMEX Oil: $6.00 - $7.00 off WTI NGL: 40% - 50% of WTI Optimizing marketing strategy to maximize realizations Commodity Prices: Flat price scenarios Commodity price improvements 0% 5% 10% 15% 20% GPOR Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 FCF Yield 2026 2027 5-Year Adjusted Free Cash Flow Generation Potential 2026E – 2030E Cumulative Adjusted Free Cash Flow(1,2,3,6) as % of Market Cap(6) Adjusted Free Cash Flow Yield(4,5) 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. 2. Based upon flat price cases and base assumptions per year. Includes current hedge position as of 2/19/26. 3. No payment of cash income taxes assumed in illustration. Company does not currently anticipate paying significant cash income taxes over next five years (estimating <10% of cumulative 5-year adjusted free cash flow). 4. Sourced from J.P. Morgan 2026 E&P and Natural Gas Outlook utilizing J.P. Morgan estimates & Bloomberg Finance L.P.; Strip pricing as of 12/4/25 and share prices as of 12/5/25. Peers include AR, CNX, CTRA, EQT, EXE, NFG, & RRC. 5. Adjusted FCF Yield is calculated using estimated adjusted free cash flow divided by current market capitalization. 6. Market capitalization calculated as of 2/19/26 at a price of $201.56 per share using shares outstanding from the Company’s 2025 10-K filing. • Sustainable free cash generation underpinned by high-quality assets • Meaningful adjusted free cash flow profile expected to generate a substantial portion of Company’s market capitalization (6) over the next five years • Delivering highest adjusted free cash flow yield among natural gas peers Key Highlights 0% 50% 100% 3.5 3.75 4 4.25$4.25 Gas / $65.00 Oil $4.00 Gas / $65.00 Oil $3.75 Gas / $65.00 Oil $3.50 Gas / $65.00 Oil >60% >70% >80% >90%
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GPOR | 7 18.2 MBbls/day 1.10 Bcfe/day $92.0 Million $1.25 per Mcfe $120.2 Million $135.0 Million 18.7 MBbls/day 1.04 Bcfe/day $463.2 Million $1.25 per Mcfe $324.7 Million $336.3 Million $47.2 Million $62.9 Million 0.9x Fourth Quarter and Full Year 2025 Results 1. Excludes $0.5 million non-D&C capital and $1.9 million non-operated D&C capital for 4Q2025. Excludes $6.7 million non -D&C capital and $4.1 million of non-operated D&C capital for FY2025. 2. Includes LOE, GP&T and taxes other than income. 3. Adjusted EBITDA and adjusted free cash flow are non -GAAP financial measures; see supplemental slides. Adjusted free cash flow ex cludes discretionary acreage acquisitions and equity repurchases. 4. As of 12/31/2025 using net debt to LTM Adjusted EBITDA. Net debt and Adjusted EBITDA are non -GAAP measures. Net debt is defined as total long-term debt minus cash and cash equivalents. 5. Includes redemption of preferred equity totaling $31.3 million or ~180,000 shares of common stock on an as -converted basis based on redemption price of $174.22. • Delivered total net production of 1.04 Bcfe per day • Produced total net liquids production of 18.7 MBbl per day, an increase of approximately 29% over full year 2024 • Maintained a strong balance sheet and low financial leverage, with liquidity at December 31, 2025 totaling $806.1 million • Expanded common stock repurchase authorization by 50% percent to a total of $1.5 billion, with approximately $579.6 million remaining at December 31, 2025 • Repurchased approximately 1.8 million shares of common stock (including preferred stock on an as-converted basis) for approximately $336.3 million, including the optional redemption of all the Company's outstanding preferred stock for approximately $31.3 million • Allocated $62.9 million toward discretionary acreage acquisitions, expanding high-quality resource base • Expanded undeveloped Marcellus inventory through delineation and development, capturing significant value and growing Marcellus inventory to more than four years at current development pace • Completed successful U-development in the Utica, unlocking 20 gross high- return Utica dry gas locations Key Highlights T otal Liquids Net Production T otal Net Production 4Q2025 Incurred Capital Expenditures(1) Per Unit Operating Cost(2) Quarter-end Leverage (Net Debt(4) to Adjusted EBITDA(3)) Adjusted Free Cash Flow(3) Common Stock Repurchases(5) FY2025 Discretionary Acreage Acquisitions
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GPOR | 8 Significant Low Break-Even Inventory Expansion 1. Year-end inventory adjusted for annual development activity. 2. Based on assumed development cadence of approximately 20 to 25 wells per year. 3. PV-10 breakeven price includes all-in wells costs, gathering, processing, transport, pricing differentials, LOE and production taxes. WTI realization used for the analysis was $65/Bbl. Dec-22 Inventory 2023 Additions Dec-23 Inventory 2024 Additions Dec-24 Inventory 2025 Additions Current Inventory Ongoing Gross Locations Discretionary Acreage Marcellus Single Well U-Development Key Highlights >40% Increase in Gross Undeveloped Inventory Since 2022(1) Continuously adding high-quality inventory through acquisition, delineation and optimization >700 Gross Locations ~500 ~550 ~560 >700 +75 +35 >170 ~15 years(2) net inventory breaks even under $2.50/MMBtu(3) High-quality, multi-basin portfolio >700 Gross Locations Utica Dry Gas Utica Wet Gas Utica Condensate Marcellus SCOOP Gross Undeveloped Inventory • Since year-end 2022, Gulfport’s gross undeveloped inventory has increased by more than 40%, driven by targeted discretionary acreage acquisitions, Marcellus delineation and U-development initiatives • Estimate >700 gross locations and roughly 15 years of net inventory with break-evens below $2.50 per MMBtu • Achieving high end of previously announced discretionary acreage acquisition program, expecting to allocate in total $100 million by the end of 1Q2026, with $62.9 million deployed as of year end 2025 (1) (1) (1) (1)
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GPOR | 9 Inventory Expansion Adding High Quality Resource Depth 1. Based on flat $3.75 / MMBtu natural gas and $65 / Bbl oil. Average internal rates of returns based on actual planned lateral lengths and type curves for each defined development area over the next five years of development. 2. Based on assumed development cadence of approximately 20 to 25 wells per year. 3. Assumes completion of previously announced discretionary acreage acquisition program, expecting to allocate in total $100 million by the end of 1Q2026. Key Highlights • Strategic discretionary acreage acquisitions has added quality inventory, optionality to near-term development and strengthened the long-term value of the Company • Peer activity and learnings from Gulfport’s development has expanded Marcellus resource viability to the north, increasing Marcellus inventory by ~200% 0% 100% $- $1,000 Marcellus North Marcellus Core Utica Condensate Utica Wet Gas Utica Dry Gas Rates of Return Average Well Cost ($/ft) Utica dry gas, Utica liquids and Marcellus providing returns ~70%+ IRR Attractive Rates of Return(1) Discretionary Acreage Acquisitions Marcellus development and delineation capturing significant value, >4 years(2) of drillable inventory Marcellus Delineation <$800 / ft <$800 / ft <$800 / ft ~$800 / ft ~$900 / ft Discretionary acreage acquisitions will have added >4.5 years(2,3) since 2022, within the wet gas and dry gas windows Legend Gulfport Utica Acreage Legend Gulfport Marcellus Acreage Marcellus Development Recent target areas include Belmont and Monroe Counties Marcellus North Ongoing Assessment Marcellus Core
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GPOR | 10 1. Adjusted free cash flow is a non-GAAP financial measure; see supplemental slides. Adjusted free cash flow excludes discretionary acreage acquisitions and equity repurchases. 2. Based on $4.00 NYMEX / $65 WTI flat price case. Includes current hedge position as of 2/19/26. Full Year 2026 Guidance Key Operational / Financial Highlights T otal Liquids Net Production T otal Net Production Incurred Operated D&C Expenditures Maintenance Land and Seismic Common Share Repurchases 18.0 – 21.0 MBbl/day 1.030 – 1.055 Bcfe/day $365 – $390 Million $35 – $40 Million Expect to maintain an active repurchase program through 2026 Adjusted Free Cash Flow(1) Estimated >40%(2) increase year-over-year Key Highlights • Adjusted free cash flow expected to grow meaningfully, driven by disciplined, return-focused capital allocation that prioritizes highest-return development opportunities • Forecast 4Q2026 net daily equivalent production to grow ~5% compared to 4Q2025 • Full year production impacted by temporary headwinds from known production downtime and Winter Storm Fern • Production expected to strengthen 2H2026 as new wells come online and known production downtime eases • Targeting majority of our development efforts in the dry gas and wet gas windows of the Utica • Plan total capital expenditures of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments • Capital plans include ~$15 million allocated to base production support with high-return workovers that enhance well productivity and reduce underlying decline rates • Marcellus focus with ~$10 million investment directed toward drilling 2 wells (DUC) in the northern portion of the play to evaluate thermal maturity and production mix in preparation for midstream planning
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GPOR | 11 - 1,200 1Q2026E 2Q2026E 3Q2026E 4Q2026E MMcfe/day Natural Gas NGL Oil - 1,200 4Q2025 4Q2026E Capital Program • Anticipate total operated D&C capital of $365 – $390 million, which includes workover and incremental Marcellus capital compared in FY2025 • Forecast investing $35 – $40 million on maintenance land and seismic • Achieving high end of previously announced discretionary acreage acquisition program, expecting to allocate in total $100 million by the end of 1Q2026, with $62.9 million deployed as of year end 2025 Production • Forecast ~5% production increase in 4Q2026 versus 4Q2025 • Expect full year total net daily equivalent production in the range of 1.030 – 1.055 Bcfe/day • Production estimates includes impacts by known simops/midstream downtime and Winter Storm Fern • Increasing development in highly economic wet gas area of the Utica $0 $200 1Q2026E 2Q2026E 3Q2026E 4Q2026E $ Millions Utica Marcellus SCOOP Maintenance Land & Seismic 2026 Capital Program and Production Outlook Total Capital Expenditures Total Net Production
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GPOR | 12 2026 Development Plan Overview • Extended Utica inventory by >5.5 years(1,2) since year-end 2022 • Discretionary acreage acquisitions will have added >4.5 years(1), within the wet gas and dry gas windows of the play • Trending toward the high end of existing targeted discretionary acreage acquisition program, expecting to allocate in total $100 million by the end of 1Q2026, with $62.9 million deployed as of year end 2025 • Validation of U-development unlocked ~1 year(1) of dry gas inventory • Plan to drill 18 gross wells and turn-to-sales 20 gross wells during 2026 Utica Key Highlights • Marcellus development is within Utica footprint and captures value enhancement through stacked pay synergies and liquids optionality • Estimate 95 – 105 net locations, >4 years(1) of drillable inventory • Plan to drill 6 gross wells and turn-to-sales 4 gross wells during 2026 Marcellus Key Highlights 1. Based on assumed development cadence of approximately 20 to 25 wells per year. 2. Assumes completion of existing discretionary acreage acquisition program, expecting to allocate in total $100 million by the end of 1Q2026. • Targeting high return, liquids-rich development in the SCOOP • Plan to drill and turn-to-sales 2 gross wells during 2026 SCOOP Key Highlights Legend Gulfport Utica Acreage Pads Turned-in-Line Marcellus 4-Well Pad Spud: 4Q2025 TIL: 2Q2026 2-Well Pad U-Development Spud: 4Q2025 TIL: 1Q2026 3-Well Pad Spud: 3Q2025 TIL: 1Q2026 4-Well Pad Spud: 1Q2026 TIL: 2Q2026 4-Well Pad Spud: 1Q2026 TIL: 3Q2026 4-Well Pad Spud: 2Q2026 TIL: 3Q2026 3-Well Pad Spud: 2Q2026 TIL: 4Q2026 3-Well Pad Spud: 3Q2026 Marcellus 2-Well Pad Spud: 3Q2025 3-Well Pad Spud: 4Q2026
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GPOR | 13 Utica Dry Gas 12 gross (11.6 net) 14,600’ Utica Wet Gas 8 gross (7.9 net) 19,500’ Utica Condensate - - Marcellus 4 gross (4.0 net) 16,100’ SCOOP 2 gross (1.7 net) 9,500’ Utica Dry Gas 18 gross (18.0 net) 15,200’ Utica Wet Gas 4 gross (4.0 net) 17,300’ Utica Condensate 4 gross (4.0 net) 12,100’ Marcellus 4 gross (4.0 net) 8,600’ SCOOP 2 gross (1.8 net) 11,500’ Spud 2026 Development Plan Overview Well Count Lateral Drilled Completed 2025 Operated Activity Utica Dry Gas 16 gross (16.0 net) 14,000’ Utica Wet Gas 1 gross (1.0 net) 15,700’ Utica Condensate - - Marcellus 7 gross (7.0 net) 11,800’ SCOOP - - Utica Dry Gas 19 gross (18.9 net) 14,000’ Utica Wet Gas 4 gross (4.0 net) 17,300’ Utica Condensate - - Marcellus 4 gross (4.0 net) 8,600’ SCOOP 2 gross (1.8 net) 11,500’ Utica Dry Gas 20 gross (20.0 net) 15,200’ Utica Wet Gas 4 gross (4.0 net) 17,300’ Utica Condensate 4 gross (4.0 net) 12,100’ Marcellus 4 gross (4.0 net) 8,600’ SCOOP 2 gross (1.8 net) 11,500’ Note: Utica Wet Gas assumes oil yield of < 15 Bbl / MMcf. Turned-to-Sales Well Count Lateral 2026E Operated Activity Utica Dry Gas 11 gross (10.7 net) 16,400’ Utica Wet Gas 8 gross (7.9 net) 19,500’ Utica Condensate - - Marcellus 3 gross (2.6 net) 18,000’ SCOOP 2 gross (1.7 net) 9,500’ Utica Dry Gas 10 gross (9.7 net) 16,100’ Utica Wet Gas 8 gross (7.9 net) 19,500’ Utica Condensate - - Marcellus 6 gross (5.6 net) 17,000’ SCOOP 2 gross (1.7 net) 9,500’ Utica Dry Gas 10 gross (9.6 net) 15,400’ Utica Wet Gas 8 gross (7.9 net) 19,500’ Utica Condensate - - Marcellus 4 gross (4.0 net) 16,100’ SCOOP 2 gross (1.7 net) 9,500’ Utica Dry Gas Utica Wet Gas Utica Condensate Marcellus SCOOP TIL Well Mix >75% of 2026 TIL program projected to be natural gas weighted 13,500 16,900 14,000 16,000 2025 2026E Drilled TILs Average Net Lateral Length 2025 2026E
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GPOR | 14 2022 2023 2024 2025 2022 2023 2024 2025 2026E Maintaining Best-in-Class Operational Efficiencies Ohio Drilling and Completion Efficiencies Average Total Footage per Day Average Frac Pumping Hours Utica D&C Cost Per Lateral FtAverage Plugs Drilled per Day 2022 2023 2024 2025 Improved drilling efficiency by ~80% since 2022 and ~16% over FY2024 Improved completion efficiency by ~26% since 2022 and maintaining top decile performance 2022 2023 2024 2025 Improved drill out efficiency by ~102% since 2022 and maintaining top decile performance Combined efficiencies translate to D&C per ft ~33% lower since 2022 ~$920 / ft
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GPOR | 15 • Diversified and right-sized takeaway capacity • 625,000 MMBtu/d(1,3) of firm takeaway from the Utica • 200,000 MMBtu/d(1) of firm takeaway from the SCOOP • Strategic connectivity to premium basin egress pipelines provides netback enhancement while maintaining exposure to in-basin demand growth opportunities • Premium Gulf Coast transportation allows delivery to growing LNG demand center and industrial corridor at NYMEX-plus pricing • Proactively hedge in-basin exposure to secure pricing Advantaged Firm Portfolio Provides Access to Diverse Markets 1. Primary reservation volume only. Excludes zero-leg and secondary-leg reservation volume. Assumes run-rate gross reservation volume on a MMBtu/d basis. 2. Percentages represent approximate gross production exposure to basin regions. 3. Total volume reduces by 60,000 MMBtu/d on June 1, 2026. Regional Exposure(1) 2026E(2) Midwest 450,000(3) MMBtu/d firm takeaway 30% - 40% Gulf Coast 175,000 MMBtu/d firm takeaway 10% - 15% MidCon 200,000 MMBtu/d firm takeaway 15% - 20% In-Basin Exposure 30% – 40% MidCon SCOOP Basin (NGPL TexOK, OGT, NGPL Midcon) Premium Gulf Coast (TGP 500L, Transco St 85) Midwest (Chicago CG, REX Z3, Lebanon) Utica Basin (Tetco M2, TGP 200L)
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GPOR | 16 $0 $100 $200 $300 $400 $500 $600 $700 $800 $900 $1,000 2026 2027 2028 2029 ($ Millions) No Maturities Until 2028 Fourth Quarter 2025 Overview Strong Capital Structure and Financial Profile 1. Liquidity as of 12/31/25 and calculated as $1.8 million cash plus $804.3 million borrowing base availability, which takes into effect $147.0 million of borrowings on revolver and $48.7 million of letters of credit. 2. As of 12/31/2025 using net debt to TTM Adjusted EBITDA. Net debt is a non-GAAP measure. It is defined as total long-term debt minus cash and cash equivalents. 3. Includes redemption of preferred equity totaling $31.3 million for ~180,000 shares of common stock on an as-converted basis based on redemption price of $174.22. As of December 31, 2025 Coupon 6.750% $650 Outstanding L/Cs Total Elected Commitments Senior Notes Maturity Sept 2029 Cash and Liquidity • $1.8 million of cash equivalents • ~$806 million of liquidity(1) Debt • $147 million borrowings under credit facility • $650 million of senior notes due 2029 • Leverage of ~0.9x(2) Equity • Redeemed 2,449 shares of preferred stock for ~$31.3 million on September 5, 2025 • Prior to redemption date, 28,907 shares of preferred stock were converted into ~2.1 million shares of common stock • No shares of preferred stock remain outstanding • Common stock: 18.8 million shares • Equity repurchase program authorized for up to $1.5 billion • Repurchased ~$920.4(3) million as of December 31, 2025 Maturity Sept 2028 $1.1B Borrowing Base $1,000 Borrowings under Credit Facility Elected Commitment Under Credit Facility $1.1B Borrowing Base
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GPOR | 17 • Achieved overall “A” rating for Appalachia assets from MiQ for third consecutive year • Applied key learnings from Appalachia, such as comprehensive leak detection program, elimination of natural gas-driven pneumatic devices and advanced methane detection and monitoring technologies, to Mid-Continent assets • Continued to lower Scope 1 methane intensity(1), improving by 20% year- over-year and 33% since 2022 • Conducted climate risk assessment and integrated climate-related risk into Enterprise Risk Management (ERM) program Focused on Continuous Improvement and Responsible Stewardship • Reduced combined total recordable incident rate by 44% year-over-year, exceeding Company wide targets and recording the strongest annual safety performance to date • Partnered with organizations that support Gulfport’s key focus areas: education, health and human services, environmental stewardship and military and veterans • Paid over $235 million in royalties to local landowners and working interest owners in 2024 • Experienced 7-member board including 6 independent directors • 40% of directors identifying as gender or ethnically diverse • Maintained separation of Chief Executive Officer and Chair roles while retaining Lead Independent Director • Continued environmental, safety and governance short-term compensation incentive metrics with a 30% weighting EnvironmentalSocial Governance Reduced Combined Total Recordable Incident Rate 54 % since 2022 Vendor Code of Conduct can be found on Gulfport’s website Improved Methane Intensity Rate 33% (1) since 2022 For additional information please refer to Gulfport’s Corporate Sustainability Report Note: More details on our initiatives can be found on the Gulfport website: www.gulfportenergy.com 1. Reported full year 2024 and based on EPA required Subpart W reporting. www.gulfportenergy.com/sustainability
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Appendix
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GPOR | 19 Utica 73% Marcellus 5% SCOOP 22% SEC YE 2025 YE 2025 YE 20252 YE 20253 PDP PDNP PUD ~$3.6 Billion ~$3.4 Billion(4) ~$4.2 Billion(4) ~$5.0 Billion(4) 2025 Proved Reserve Summary 1. Per Company reserve report for year ending 12/31/25. 2. Proved undeveloped reserves, under SEC reserve reporting guidelines, only includes wells scheduled to be drilled within the next five years. 3. PV-10 is a non-GAAP measure; see supplemental slides. 4. Flat price cases at stated price scenarios. Net Reserves as of December 31, 2025(1) Gas Oil NGL Total (Bcf) (MMBbls) (MMBbls) (Bcfe) Proved Developed Producing 2,089 8 32 2,329 Proved Developed Non-Producing 68 0 1 75 Proved Undeveloped(2) 1,455 16 50 1,848 Total Proved Reserves 3,612 24 83 4,253 Proved Reserve Components SEC Year End Proved Reserves PV-10(3,4) $3.75 Gas / $65.00 Oil $3.25 Gas / $65.00 Oil $3.39 Gas / $66.01 Oil $4.25 Gas / $65.00 Oil Nat Gas 85% NGL 12% Oil 3% PDP 55% PDNP 2% PUD 43% Commodity Category Basin
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GPOR | 20 Incurred Capital Expenditures – $ millions Operated D&C Capital Expenditures $365 $390 Maintenance Land and Seismic $35 $40 T otal Capital Expenditures $400 $430 Production Net Daily Gas Equivalent – Bcfe/day 1.030 1.055 Net Daily Liquids Production – MBbls/day 18.0 21.0 % Gas ~89% Realizations (before hedges)(1) Natural Gas (Differential to NYMEX) - $/Mcf ($0.15) ($0.30) NGL (% of WTI) 40% 50% Oil (Differential to NYMEX WTI) - $/Bbl ($6.00) ($7.00) Expenses Lease Operating Expense - $/Mcfe $0.21 $0.25 Taxes Other Than Income - $/Mcfe $0.07 $0.09 GPT&C - $/Mcfe $0.95 $1.00 Recurring Cash G&A(2) - $/Mcfe $0.12 $0.14 Full Year 2026 Guidance FY 2026E Note: Guidance for the year ending 12/31/26 is based on multiple assumptions and certain analyses made by the Company based o n its experience and perception of historical trends and current conditions and may change due to future developments. Actual re sults may not conform to the Company’s expectations and predictions. Please refer to page 2 for more detail of forward -looking statements. 1. Based upon current forward pricing at February 2, 2026 and basis marks. 2. Recurring cash G&A is a non-GAAP financial measures; see supplemental slides. 3. Adjusted free cash flow is a non-GAAP financial measures; see supplemental slides. Excludes discretionary acreage acquisitions and common stock repurchases. • Expect to maintain an active repurchase program through 2026, supported by adjusted free cash flow(3) (excluding discretionary acreage acquisitions) and revolver capacity with leverage maintained at approximately 1.0x or below • Continue to reinvest cash flows into accretive discretionary acreage acquisitions that expand high quality resource depth and strengthen long-term value of the Company 2026E Adjusted Free Cash Flow Generation Guidance FY 2026E Guidance
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GPOR | 21 Tetco M2 Basis Rex Zone 3 Basis NGPL TXOK Basis TGP 500 Basis Transco Station 85 Basis Swaps Swaps Swaps Swaps Swaps Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Price $/MMBtu 1Q 2026 170,000 ($0.95) 80,000 ($0.18) 30,000 ($0.30) 20,000 $0.56 10,000 $0.56 2Q 2026 170,000 ($0.95) 80,000 ($0.18) 30,000 ($0.30) 20,000 $0.56 10,000 $0.56 3Q 2026 170,000 ($0.95) 80,000 ($0.18) 30,000 ($0.30) 20,000 $0.56 10,000 $0.56 4Q 2026 170,000 ($0.95) 80,000 ($0.18) 30,000 ($0.30) 20,000 $0.56 10,000 $0.56 FY 2026 170,000 ($0.95) 80,000 ($0.18) 30,000 ($0.30) 20,000 $0.56 10,000 $0.56 1Q 2027 100,000 ($0.85) 50,000 ($0.19) 40,000 ($0.33) - - - - 2Q 2027 100,000 ($0.85) 50,000 ($0.19) 40,000 ($0.33) - - - - 3Q 2027 100,000 ($0.85) 50,000 ($0.19) 40,000 ($0.33) - - - - 4Q 2027 100,000 ($0.85) 50,000 ($0.19) 40,000 ($0.33) - - - - FY 2027 100,000 ($0.85) 50,000 ($0.19) 40,000 ($0.33) - - - - Natural Gas Oil Propane Swaps Collars Collars Swaps Volume MMBtu/d Avg. Price $/MMBtu Volume MMBtu/d Avg. Put $/MMBtu Avg. Call $/MMBtu Volume Bbl/d Avg. Put $/Bbl Avg. Call $/Bbl Volume Bbl/d Avg. Price $/Bbl 1Q 2026 336,222 $3.81 170,000 $3.69 $4.41 742 55.00 70.85 3,000 $30.67 2Q 2026 350,000 $3.81 150,000 $3.61 $4.35 1,250 55.00 71.24 3,000 $30.67 3Q 2026 350,000 $3.81 150,000 $3.61 $4.35 1,250 55.00 71.24 2,000 $31.25 4Q 2026 350,000 $3.81 150,000 $3.61 $4.35 1,250 55.00 71.24 2,000 $31.25 FY 2026 346,603 $3.81 154,932 $3.63 $4.37 1,125 55.00 71.18 2,496 $30.91 1Q 2027 210,000 $3.93 110,000 $3.75 $4.27 300 55.00 68.00 - - 2Q 2027 210,000 $3.93 110,000 $3.75 $4.27 300 55.00 68.00 - - 3Q 2027 210,000 $3.93 110,000 $3.75 $4.27 300 55.00 68.00 - - 4Q 2027 210,000 $3.93 110,000 $3.75 $4.27 300 55.00 68.00 - - FY 2027 210,000 $3.93 110,000 $3.75 $4.27 300 55.00 68.00 - - Hedged Production Natural Gas, Oil and Propane Hedge Summary (1) 1. As of 2/19/25. Basis Hedge Summary(1)
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GPOR | 22 Adjusted EBITDA is a non-GAAP financial measure equal to net income (loss), the most directly comparable GAAP financial measure, plus interest expense, income tax expense (benefit), depreciation, depletion and amortization, impairment and accretion, net non-cash derivative loss (gain), non-recurring general and administrative expenses comprised of expenses related to the continued administration of our prior Chapter 11 filing, stock-based compensation, loss on debt extinguishment and other items which include non -material expenses. Below is a reconciliation of net income (loss) (a GAAP measure) to Adjusted EBITDA. This non -GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. Adjusted EBITDA (In thousands) (Unaudited) Three Months Ended December 31, 2025 Three Months Ended December 31, 2024 Year Ended December 31, 2025 Year Ended December 31, 2024 Net income (loss) (GAAP) $ 132,415 $ (273,242) 427,810 (261,386) Adjustments: Interest expense 13,600 13,955 54,277 59,982 Income tax expense (benefit) 32,591 (59,510) 115,495 (56,077) DD&A, impairment and accretion 82,300 427,651 306,583 701,244 Non-cash derivative (gain) loss (29,504) 86,656 (42,559) 253,110 Non-recurring general and administrative expenses 467 963 1,905 2,524 Stock-based compensation expenses 2,911 2,548 12,156 10,958 Loss on debt extinguishment — — — 13,388 Other, net(1,2) 47 3,806 2,842 7,336 Adjusted EBITDA (Non-GAAP) $ 234,827 $ 202,827 $ 878,509 $ 731,079 1. For the year ended December 31, 2025, “Other, net” included approximately $2.4million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. 2. For the year ended December 31, 2024, “Other, net” included approximately $4.9 million related to changes in the Company's legal reserves for certain litigation and regulatory proceedings. Additionally, “Other, net” included approximately $1.9 million as a result of a write-down of certain of its pipe inventory that the Company did not expect to utilize in its drilling and completion activities.
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GPOR | 23 Adjusted Free Cash Flow 1. Includes cash capitalized general and administrative expense and incurred capitalized interest expenses. 2. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle. 3. For the three months ended December 31, 2025, includes $0.5 million and $1.9 million of non-D&C capital and non-operated capital expenditures, respectively. For the year ended December 31, 2025, includes $6.7 million and $4.1 million of non-D&C capital and non-operated capital expenditures, respectively. Additionally, excludes targeted discretionary acreage acquisitions of $62.9 million. 4. For the three months ended December 31, 2024, includes $0.3 million and $1.4 million of non-D&C capital and non-operated capital expenditures, respectively. For the year ended December 31, 2024, includes $4.3 million and $3.8 million of non-D&C capital and non-operated capital expenditures, respectively. Additionally, excludes targeted discretionary acreage acquisitions of $44.8 million. Adjusted free cash flow is a non-GAAP measure defined as adjusted EBITDA plus certain non-cash items that are included in net cash provided by (used in) operating activities but excluded from adjusted EBITDA less interest expense, current income tax expense (benefit), capitalized expenses incurred and capital expenditures incurred, excluding discretionary acreage acquisitions. Gulfport includes ranges of expectations for adjusted free cash flow for 2025. We are unable, however, to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. Accordingly, Gulfport is relying on the exception provided by Item 10(e)(1)(i)(B) of Regulation S-K to exclude such reconciliation. Items excluded in net cash provided by operating activities to arrive at adjusted free cash flow include interest expense, income taxes, capitalized expenses as well as one-time items or items whose timing or amount cannot be reasonably estimated. Below is a reconciliation of net cash provided by operating activities (the most comparable GAAP measure) to adjusted free cash flow. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. (In thousands) (Unaudited) Three Months Ended December 31, 2025 Three Months Ended December 31, 2024 Year Ended December 31, 2025 Year Ended December 31, 2024 Net cash provided by operating activity (GAAP) $ 185,432 $ 148,848 $ 803,193 $ 650,033 Adjustments: Interest expense 13,600 13,955 54,277 59,982 Non-recurring general and administrative expenses 467 963 1,905 2,524 Other, net (1,697) 2,602 (3,336) 3,328 Changes in operating assets and liabilities, net Accounts receivable - oil, natural gas, and natural gas liquids sales 62,659 67,011 28,707 33,463 Accounts receivable - joint interest and other 1,372 (5,547) 555 (13,494) Accounts payable and accrued liabilities (25,805) (25,184) (8,193) (4,067) Prepaid expenses (1,191) 183 1,412 (667) Other assets (10) (4) (11) (23) Total changes in operating assets and liabilities $ 37,025 $ 36,459 22,470 15,212 Adjusted EBITDA (Non-GAAP) $ 234,827 $ 202,827 $ 878,509 $ 731,079 Interest expense (13,600) (13,955) (54,277) (59,982) Capitalized expenses incurred(1) (6,652) (6,721) (25,415) (24,712) Capital expenditures incurred, excluding discretionary acreage acquisitions (2,3,4) (94,404) (56,941) (474,118) (389,574) Adjusted free cash flow (Non-GAAP) $ 120,171 $ 125,210 $ 324,699 $ 256,811
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GPOR | 24 Recurring General and Administrative (G&A) Expense Recurring general and administrative expense is a non-GAAP financial measure equal to general and administrative expense (GAAP) plus capitalized general and administrative expense, less non-recurring general and administrative expenses comprised of expenses related to the continued administration of our prior Chapter 11 filing. Gulfport includes a recurring cash general and administrative expense estimate for 2025. We are unable, however, to provide a quantitative reconciliation of the forward-looking non-GAAP measure to its most directly comparable forward-looking GAAP measure because management cannot reliably quantify certain of the necessary components of such forward-looking GAAP measure. Accordingly, Gulfport is relying on the exception provided by Item 10 (e)(1)(i) (B) of Regulation S-K to exclude such reconciliation. Items excluded in general and administrative expense to arrive at recurring general and administrative expense include capitalized expenses as well as one -time items or items whose timing or amount cannot be reasonably estimated. Below is a reconciliation of general and administrative expense (the most comparable GAAP measure) to recurring general and a dministrative expense. This non-GAAP measure should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. (In thousands) (Unaudited) Three Months December 31, 2025 Three Months Ended December 31, 2024 Cash Non-Cash Total Cash Non-Cash Total General and administrative expense (GAAP) $ 7,815 $ 2,911 $ 10,726 $ 9,581 $ 2,548 $ 12,129 Capitalized general and administrative expense 4,910 1,434 6,344 5,552 1,256 6,808 Non-recurring general and administrative expense (467) — (467) (963) — (963) Recurring General and Administrative Expense (Non-GAAP) $ 12,258 $ 4,345 $ 16,603 $ 14,170 $ 3,804 $ 17,974 (In thousands) (Unaudited) Year Ended December 31, 2025 Year Ended December 31, 2024 Cash Non-Cash Total Cash Non-Cash Total General and administrative expense (GAAP) $ 30,332 $ 12,156 $ 42,488 $ 31,600 $ 10,958 $ 42,558 Capitalized general and administrative expense 19,260 5,987 25,247 19,940 5,398 25,338 Non-recurring general and administrative expense (1,905) — (1,905) (2,524) — (2,524) Recurring General and Administrative Expense (Non-GAAP) $ 47,687 $ 18,143 $ 65,830 $ 49,016 $ 16,356 $ 65,372
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GPOR | 25 Present value of estimated future net revenue (PV-10) Note: Reserves as of December 31, 2025 utilized prices of $66.01/Bbl of oil, $31.07/Bbl for NGLs and $3.39/MMBtu of natural gas. Reserves as of December 31, 2024 utilized prices of $76.32/Bbl of oil, $31.30/Bbl for NGLs and $2.13/MMBtu of natural gas. Prices are determined in accordance with the SEC requirement to use the unweighted arithmetic average of the first day-of-the-month price for the preceding twelve months without giving effect to derivative transactions. PV – 10 is a non-GAAP measure derived from standardized measure of discounted future new cash flows (GAAP). Management uses PV -10, which is calculated without deducting estimated future income tax expenses, as a measure of the value of the Company's current proved reserves and to compare relative values among peer companies. We also understand that securities analysts and rating agencies use this measure in similar ways. While estimated future net revenue and the present value thereof are based on prices, costs and discount factors which may be consi stent from company to company, the standardized measure of discounted future net cash flows is dependent on the unique tax situation of each individual company. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company's financial or operating performance presented in accordance with GAAP. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves. (In thousands) (Unaudited) December 31, 2025 December 31, 2024 Proved Developed Proved Undeveloped Total Proved Proved Developed Proved Undeveloped Total Proved Estimated future net revenue $3,816 $3,145 $6,961 $1,620 $1,876 $3,496 Present value of estimated future net revenue (PV-10) $2,291 $1,331 $3,622 $1,059 $699 $1,757 Standardized measure $3,403 $1,747
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Thank You. Investor Relations 405.252.4550 investor_relations@gulfportenergy.com www.gulfportenergy.com