Annual report [Section 13 and 15(d), not S-K Item 405]

SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)

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SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
 12 Months Ended
Dec. 31, 2025
Extractive Industries [Abstract]  
SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED) SUPPLEMENTAL INFORMATION ON OIL AND GAS EXPLORATION AND PRODUCTION ACTIVITIES (UNAUDITED)
The Company is making the following supplemental disclosures of oil and gas activities, in accordance with the full cost method of accounting for its oil and gas exploration and development activities. The Company owns a 24.5% interest in Grizzly. However, Grizzly did not have any material activity or proved reserves in the years presented below. As such, amounts related to Grizzly have been omitted below.
The following table provides historical revenue and cost information relating to the Company’s oil and gas operations located entirely in the United States:
Capitalized Costs Related to Oil and Gas Producing Activities (in thousands)
Year Ended December 31, 2025 Year Ended December 31, 2024
Proved properties $ 3,902,539  $ 3,349,805 
Unproved properties 232,959  221,650 
Total oil and natural gas properties 4,135,498  3,571,455 
Accumulated depletion and amortization (1,861,570) (1,559,546)
Net capitalized costs $ 2,273,928  $ 2,011,909 
Costs Incurred in Oil and Gas Property Acquisition, Development and Exploratory Activities (in thousands)
Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023
Acquisition $ 83,601  $ 89,646  $ 93,905 
Development 480,442  373,284  419,431 
Exploratory —  —  — 
Total $ 564,043  $ 462,930  $ 513,336 
Capitalized interest is included as part of the cost of oil and natural gas properties. The Company capitalized $6.2 million, $4.8 million and $4.1 million for the years ended December 31, 2025, 2024 and 2023, respectively, based on the Company's weighted average cost of borrowings used to finance expenditures.
In addition to capitalized interest, the Company capitalized internal costs totaling $25.2 million, $25.3 million and $22.8 million during the years ended December 31, 2025, 2024, and 2023, respectively, which were directly related to the acquisition, exploration and development of the Company's oil and natural gas properties.
Results of Operations for Producing Activities (in thousands)
The following table sets forth the revenues and expenses related to the production and sale of oil and natural gas. The income tax expense is calculated by applying the current statutory tax rates to the revenues after deducting costs, which include depreciation, depletion and amortization allowances, after giving effect to the permanent differences. The results of operations exclude general office overhead and interest expense attributable to oil and gas production.
Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023
Revenues $ 1,323,527  $ 928,604  $ 1,051,383 
Production costs (473,088) (451,086) (450,996)
Depletion (302,024) (324,078) (318,473)
Impairment —  (373,214) — 
Income tax (expense) benefit (115,495) 56,077  525,156 
Results of operations from producing activities $ 432,920  $ (163,697) $ 807,070 
Depletion per Mcf of gas equivalent (Mcfe) $ 0.80  $ 0.84  $ 0.83 
Oil and Natural Gas Reserves
The following table presents estimated volumes of proved developed and undeveloped oil and gas reserves as of December 31, 2025, 2024 and 2023 and changes in proved reserves during the last three years. The reserve reports use an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the 12-month period ended December 31, 2025, 2024 and 2023, in accordance with guidelines of the SEC applicable to reserves estimates. The prices used for the 2025 reserve report are $66.01 per barrel of oil, $3.39 per MMbtu for natural gas and $30.17 per barrel for NGL, adjusted by lease for transportation fees and regional price differentials, and for oil and gas reserves, respectively. The prices used at December 31, 2024 and 2023 for reserve report purposes are $76.32 per barrel, $2.13 per MMbtu and $31.30 per barrel for NGL and $78.21 per barrel, $2.64 per MMbtu and $31.42 per barrel for NGL, respectively.
Gulfport emphasizes that the volumes of reserves shown below are estimates which, by their nature, are subject to revision. The estimates are made using all available geological and reservoir data, as well as production performance data. These estimates are reviewed annually and revised, either upward or downward, as warranted by additional performance data.
Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Natural Gas Equivalent (Bcfe)
Proved Reserves
December 31, 2022 18  3,612  54  4,048 
Purchases of reserves —  —  —  — 
Extensions and discoveries 6  875  14  996 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates (4) (411) (1) (445)
Current production (1) (350) (4) (385)
December 31, 2023 19  3,725  63  4,214 
Purchases of reserves —  —  —  — 
Extensions and discoveries 5  398  20  547 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates —  (413) 1  (406)
Current production (1) (354) (4) (386)
December 31, 2024 22  3,356  80  3,969 
Purchases of reserves —  —  —  — 
Extensions and discoveries 3  616  11  701 
Sales of reserves —  —  —  — 
Revisions of prior reserve estimates 1  (22) (4) (38)
Current production (2) (338) (5) (379)
December 31, 2025 24  3,612  83  4,253 
Proved developed reserves
December 31, 2022 9  2,034  34  2,295 
December 31, 2023 6  1,980  31  2,203 
December 31, 2024 7  1,879  31  2,109 
December 31, 2025 8  2,157  33  2,404 
Proved undeveloped reserves
December 31, 2022 9  1,578  20  1,752 
December 31, 2023 12  1,746  32  2,011 
December 31, 2024 15  1,478  49  1,861 
December 31, 2025 16  1,455  50  1,848 
Totals may not sum or recalculate due to rounding.
2025 Activity
In 2025, the Company experienced extensions of 701 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 382 Bcfe was attributable to the addition of 28 Utica PUD locations, 62 Bcfe was attributable to the addition of 7 Marcellus PUD locations, and 138 Bcfe was attributable to the addition of 6 SCOOP PUD locations. The Company also added 11 operated locations in the Utica to PDP which were not previously booked for 119 Bcfe.The Company experienced total downward revisions of 38 Bcfe in estimated proved reserves. These consisted of upward revisions of 255 Bcfe which were associated with commodity price changes. Commodity prices experienced volatility throughout 2025 and the 12-month unweighted average first-day-of-the-month price for natural gas increased from $2.13 per MMBtu for 2024 to $3.39 per MMBtu for 2025, the 12-month average WTI spot price for crude oil decreased from $76.32 per barrel for 2024 to $66.01 per barrel for 2025, and the calculated average weighted price for NGL over the remaining lives of the properties decreased from $31.30 per barrel for 2024 to $30.17 per barrel for 2025. Additionally, there were upward revisions of 161 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts throughout 2025. These were offset by downward revisions of 185 Bcfe and 129 Bcfe as a result of development schedule changes and PUD well design changes, respectively. The schedule changes moved the development of 9 Utica PUD locations and 4 SCOOP PUD locations beyond the SEC requirement of development within five years from initial booking and while these locations are excluded from our SEC reserves report, they remain in our longer-term development plan. Design changes primarily include well spacing and lateral length updates with a portion of these volumes now to be developed with locations outside of the SEC designated five-year development time frame. These development schedule and design changes reflect our ongoing commitment to optimizing the long-term plan to best develop our assets and maximize cash flow and overall economic returns. Finally, downward revisions of 141 Bcfe were a result of a combination of various economic assumptions and well performance updates.
2024 Activity
In 2024, the Company experienced extensions of 547.5 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 340.7 Bcfe was attributable to the addition of 33 Utica PUD locations, 92.4 Bcfe was attributable to the addition of 13 Marcellus PUD locations, and 114.4 Bcfe was attributable to the addition of 16 SCOOP PUD locations. The Company experienced total downward revisions of 406.0 Bcfe in estimated proved reserves. These consisted of upward revisions of 16.2 Bcfe as a result of positive well performance and 171.2 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2024. These were offset by downward revisions of 487.9 Bcfe which were due to commodity price changes. Commodity prices experienced volatility throughout 2024 and the 12-month average price for natural gas decreased from $2.64 per MMBtu for 2023 to $2.13 per MMBtu for 2024, the 12-month average price for NGL decreased from $31.42 per barrel for 2023 to $31.30 per barrel for 2024, and the 12-month average price for crude oil decreased from $78.21 per barrel for 2023 to $76.32 per barrel for 2024. Additionally, downward revisions of 172.4 Bcfe were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Finally, upward revisions of 66.9 Bcfe were a result of a combination of various economic assumption updates.
2023 Activity
In 2023, the Company experienced extensions of 995.7 Bcfe of estimated proved reserves, which were primarily attributable to the Company's continued development of its Utica/Marcellus and SCOOP acreages. Of the total extensions, 789.2 Bcfe was attributable to the addition of 67 Utica PUD locations, 88.6 Bcfe was attributable to the addition of 12 Marcellus PUD locations, and 110.4 Bcfe was attributable to the addition of 14 SCOOP PUD locations. The Company experienced total downward revisions of 444.9 Bcfe in estimated proved reserves. These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023. These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking. The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset and maximize cash flow and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe due to commodity price changes. Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL increased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023. Finally, downward revisions of 49.1 Bcfe were a result of a combination of various economic assumption updates.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The following tables present the estimated future cash flows, and changes therein, from Gulfport’s proven oil and gas reserves as of December 31, 2025, 2024 and 2023 using an unweighted average first-of-the-month price for the year January through December 31, 2025, 2024 and 2023. The average gas prices used were $3.39, $2.13 and $2.64 per MMbtu, for the years ended December 31, 2025, 2024 and 2023, respectively. The average oil prices used were $66.01, $76.32 and $78.21 per Bbl, for the years ended December 31, 2025, 2024 and 2023, respectively. The average NGL prices used were $30.17, $31.30 and $31.42 per Bbl, for the years ended December 31, 2025, 2024 and 2023, respectively.
Year ended operating expenses, development costs and appropriate statutory income tax rates, with consideration of future tax rates, were used to compute the future net cash flows. All cash flows were discounted at 10% to reflect the time value of cash flows, without regard to the risk of specific properties. The estimated future costs to develop proved developed non-producing and proved undeveloped reserves are approximately $337.2 million in 2026, $328.4 million in 2027 and $311.2 million in 2028. Estimated future development costs include capital spending on major development projects. Gulfport believes cash flow from its operating activities, cash on hand and borrowings under its Credit Facility will be sufficient to cover these estimated future development costs.
The assumptions used to derive the standardized measure of discounted future net cash flows are those required by accounting standards and do not necessarily reflect the Company's expectations. The information may be useful for certain comparative purposes but should not be solely relied upon in evaluating Gulfport or its performance. Furthermore, information contained in the following table may not represent realistic assessments of future cash flows, nor should the standardized measure of discounted future net cash flows be viewed as representative of the current value of the Company's reserves. Management believes that the following factors should be considered when reviewing the information below:
•Future commodity prices received for selling the Company's net production will likely differ from those required to be used in these calculations.
•Future operating and capital costs will likely differ from those required to be used in these calculations and do not reflect cost savings of Company owned midstream operations on future operating expenses.
•Future market conditions, government regulations, reservoir conditions and risks inherent in the production of oil and condensate and gas may cause production rates in future years to vary significantly from those rates used in the calculations.
•Future revenues may be subject to different production, severance and property taxation rates.
•The selection of a 10% discount rate is arbitrary and may not be a reasonable factor in adjusting for future economic conditions or in considering the risk that is part of realizing future net cash flows from the reserves.
The following table summarizes estimated future net cash flows from natural gas and crude oil reserves (in millions):
Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023
Future cash flows $ 15,130  $ 10,474  $ 12,338 
Future development and abandonment costs (1,632) (1,498) (1,625)
Future production costs (6,266) (5,268) (5,641)
Future production taxes (270) (212) (303)
Future income taxes (547) (23) (63)
Future net cash flows 6,414  3,473  4,706 
10% discount to reflect timing of cash flows (3,012) (1,726) (2,323)
Standardized measure of discounted future net cash flows $ 3,403  $ 1,747  $ 2,383 
Totals may not sum or recalculate due to rounding.
Future development and abandonment costs include not only development costs but also all future costs to settle asset retirement obligations. The following table summarizes the total of all future costs to settle asset retirement obligations that are included in future development and abandonment costs above (in millions):
Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023
Future asset retirement obligations $ 255  $ 240  $ 229 
Changes in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves
The principal source of change in the standardized measure of discounted future net cash flows relating to proved reserves is presented in the table below (in millions):
Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023
Sales and transfers of oil and gas produced, net of production costs $ (850) $ (478) $ (600)
Net changes in prices, production costs, and development costs 1,532  (910) (7,181)
Acquisition of oil and gas reserves in place —  —  — 
Extensions and discoveries 518  368  581 
Previously estimated development costs incurred during the period 246  211  263 
Revisions of previous quantity estimates, less related production costs (21) (21) (278)
Sales of oil and gas reserves in place —  —  — 
Accretion of discount 175  238  828 
Net changes in income taxes (209) 16  1,219 
Change in production rates and other 266  (60) (728)
Total change in standardized measure of discounted future net cash flows $ 1,656  $ (636) $ (5,896)