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What changed in GULFPORT ENERGY CORP's 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of GULFPORT ENERGY CORP's 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+281 added−302 removedSource: 10-K (2026-02-25) vs 10-K (2025-02-26)

Top changes in GULFPORT ENERGY CORP's 2025 10-K

281 paragraphs added · 302 removed · 241 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

77 edited+5 added−6 removed81 unchanged
Biggest change(2) The three gross wells that were drilled in 2024 were completed as producing wells as of December 31, 2024. 11 Table of Contents Index to Financial Statements Production, Prices and Production Costs The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas sales Natural gas production volumes (MMcf) 354,154 350,306 322,366 Natural gas production volumes (MMcf) per day 968 960 883 Total sales $ 714,160 $ 831,812 $ 1,998,452 Average price without the impact of derivatives ($/Mcf) $ 2.02 $ 2.37 $ 6.20 Impact from settled derivatives ($/Mcf) $ 0.80 $ 0.42 $ (3.11) Average price, including settled derivatives ($/Mcf) $ 2.82 $ 2.79 $ 3.09 Oil and condensate sales Oil and condensate production volumes (MBbl) 1,459 1,363 1,610 Oil and condensate production volumes (MBbl) per day 4 4 4 Total sales $ 101,589 $ 99,854 $ 147,444 Average price without the impact of derivatives ($/Bbl) $ 69.64 $ 73.27 $ 91.58 Impact from settled derivatives ($/Bbl) $ 0.11 $ (2.53) $ (24.32) Average price, including settled derivatives ($/Bbl) $ 69.75 $ 70.74 $ 67.26 NGL sales NGL production volumes (MBbl) 3,818 4,386 4,483 NGL production volumes (MBbl) per day 10 12 12 Total sales $ 112,855 $ 119,717 $ 184,963 Average price without the impact of derivatives ($/Bbl) $ 29.56 $ 27.29 $ 41.26 Impact from settled derivatives ($/Bbl) $ (0.56) $ 2.07 $ (2.80) Average price, including settled derivatives ($/Bbl) $ 29.00 $ 29.36 $ 38.46 Natural gas, oil and condensate and NGL sales Natural gas equivalents (MMcfe) 385,814 384,802 358,924 Natural gas equivalents (MMcfe) per day 1,054 1,054 983 Total sales $ 928,604 $ 1,051,383 $ 2,330,859 Average price without the impact of derivatives ($/Mcfe) $ 2.41 $ 2.73 $ 6.49 Impact from settled derivatives ($/Mcfe) $ 0.73 $ 0.40 $ (2.94) Average price, including settled derivatives ($/Mcfe) $ 3.14 $ 3.13 $ 3.55 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.18 $ 0.18 $ 0.18 Average taxes other than income ($/Mcfe) 0.08 0.09 0.17 Average transportation, gathering, processing and compression ($/Mcfe) 0.91 0.91 1.00 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.17 $ 1.17 $ 1.34 Totals may not sum or recalculate due to rounding. 12 Table of Contents Index to Financial Statements The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2024: Year Ended December 31, 2024 Year Ended December 31, 2023 Year Ended December 31, 2022 Utica & Marcellus Net Production Natural gas (MMcf) 296,548 279,428 246,123 Oil (MBbl) 847 255 244 NGL (MBbl) 1,072 856 885 Total (MMcfe) 308,060 286,095 252,895 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 1.99 $ 2.34 $ 6.14 Oil ($/Bbl) $ 66.84 $ 70.18 $ 90.60 NGL ($/Bbl) $ 37.01 $ 33.63 $ 48.21 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.16 $ 0.16 $ 0.17 Average taxes other than income ($/Mcfe) 0.06 0.05 0.06 Average transportation, gathering, processing and compression ($/Mcfe) 0.93 0.97 1.08 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.15 $ 1.18 $ 1.31 SCOOP Net Production Natural gas (MMcf) 57,605 70,878 76,242 Oil (MBbl) 612 1,108 1,366 NGL (MBbl) 2,746 3,530 3,598 Total (MMcfe) 77,753 98,707 106,024 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 2.13 $ 2.53 $ 6.38 Oil ($/Bbl) $ 73.51 $ 73.98 $ 91.71 NGL ($/Bbl) $ 26.65 $ 25.76 $ 39.56 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.28 $ 0.25 $ 0.20 Average taxes other than income ($/Mcfe) 0.13 0.17 0.38 Average transportation, gathering, processing and compression ($/Mcfe) 0.83 0.73 0.78 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.24 $ 1.15 $ 1.36 Our Investments Grizzly Oil Sands .
Biggest change(2) The two gross operated wells that were drilled in 2025 were completed as producing wells as of December 31, 2025. 11 Table of Contents Index to Financial Statements Production, Prices and Production Costs The following table presents our production volumes, average prices received and average production costs during the periods indicated (sales totals in thousands): Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023 Natural gas sales Natural gas production volumes (MMcf) 338,296 354,154 350,306 Natural gas production volumes (MMcf) per day 927 968 960 Total sales $ 1,056,429 $ 714,160 $ 831,812 Average price without the impact of derivatives ($/Mcf) $ 3.12 $ 2.02 $ 2.37 Impact from settled derivatives ($/Mcf) $ 0.14 $ 0.80 $ 0.42 Average price, including settled derivatives ($/Mcf) $ 3.26 $ 2.82 $ 2.79 Oil and condensate sales Oil and condensate production volumes (MBbl) 2,260 1,459 1,363 Oil and condensate production volumes (MBbl) per day 6 4 4 Total sales $ 133,644 $ 101,589 $ 99,854 Average price without the impact of derivatives ($/Bbl) $ 59.12 $ 69.64 $ 73.27 Impact from settled derivatives ($/Bbl) $ 4.04 $ 0.11 $ (2.53) Average price, including settled derivatives ($/Bbl) $ 63.16 $ 69.75 $ 70.74 NGL sales NGL production volumes (MBbl) 4,554 3,818 4,386 NGL production volumes (MBbl) per day 12 10 12 Total sales $ 133,454 $ 112,855 $ 119,717 Average price without the impact of derivatives ($/Bbl) $ 29.30 $ 29.56 $ 27.29 Impact from settled derivatives ($/Bbl) $ (0.07) $ (0.56) $ 2.07 Average price, including settled derivatives ($/Bbl) $ 29.23 $ 29.00 $ 29.36 Natural gas, oil and condensate and NGL sales Natural gas equivalents (MMcfe) 379,182 385,814 384,802 Natural gas equivalents (MMcfe) per day 1,039 1,054 1,054 Total sales $ 1,323,527 $ 928,604 $ 1,051,383 Average price without the impact of derivatives ($/Mcfe) $ 3.49 $ 2.41 $ 2.73 Impact from settled derivatives ($/Mcfe) $ 0.15 $ 0.73 $ 0.40 Average price, including settled derivatives ($/Mcfe) $ 3.64 $ 3.14 $ 3.13 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.22 $ 0.18 $ 0.18 Average taxes other than income ($/Mcfe) 0.08 0.08 0.09 Average transportation, gathering, processing and compression ($/Mcfe) 0.95 0.91 0.91 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.25 $ 1.17 $ 1.17 Totals may not sum or recalculate due to rounding. 12 Table of Contents Index to Financial Statements The following table provides a summary of our production, average sales prices and average production costs for oil and gas fields containing 15% or more of our total proved reserves as of December 31, 2025: Year Ended December 31, 2025 Year Ended December 31, 2024 Year Ended December 31, 2023 Utica & Marcellus Net Production Natural gas (MMcf) 283,667 296,548 279,428 Oil (MBbl) 1,729 847 255 NGL (MBbl) 2,183 1,072 856 Total (MMcfe) 307,137 308,060 286,095 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 3.11 $ 1.99 $ 2.34 Oil ($/Bbl) $ 58.06 $ 66.84 $ 70.18 NGL ($/Bbl) $ 34.87 $ 37.01 $ 33.63 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.20 $ 0.16 $ 0.16 Average taxes other than income ($/Mcfe) 0.05 0.06 0.05 Average transportation, gathering, processing and compression ($/Mcfe) 0.96 0.93 0.97 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.21 $ 1.15 $ 1.18 SCOOP Net Production Natural gas (MMcf) 54,629 57,605 70,878 Oil (MBbl) 531 612 1,108 NGL (MBbl) 2,371 2,746 3,530 Total (MMcfe) 72,045 77,753 98,707 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 3.19 $ 2.13 $ 2.53 Oil ($/Bbl) $ 62.59 $ 73.51 $ 73.98 NGL ($/Bbl) $ 24.18 $ 26.65 $ 25.76 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.31 $ 0.28 $ 0.25 Average taxes other than income ($/Mcfe) 0.17 0.13 0.17 Average transportation, gathering, processing and compression ($/Mcfe) 0.88 0.83 0.73 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.36 $ 1.24 $ 1.15 Our Investments Grizzly Oil Sands .
This policy insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability umbrella insurance program.
This policy insures against certain sudden and accidental risks associated with drilling, completing and operating our wells. This insurance may not be adequate to cover all losses or exposure to liability. We also carry a $51 million comprehensive general liability and umbrella insurance program.
These procedures, which are intended to ensure reliability of reserve estimations, include the following: • review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us; • verification of property ownership by our land department; • audit of year-end reserve estimates by NSAI; • direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; • review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; • provision of quarterly updates to our Board of Directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves; • annual review by our Board of Directors of our year-end reserve report and year-over-year changes in our proved reserves; • annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments, including the substitution, removal or deferral of PUD locations; and • annual review and approval by our senior management and our Board of Directors of a multi-year development plan. 6 Table of Contents Index to Financial Statements The tables below set forth information as of December 31, 2024, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL reserves, the associated estimated future net revenue, the PV-10 and the standardized measure.
These procedures, which are intended to ensure reliability of reserve estimations, include the following: • review and verification of historical production, operating, marketing and capital data, which data is based on actual production as reported by us; • verification of property ownership by our land department; • audit of year-end reserve estimates by NSAI; • direct reporting responsibilities by our reservoir engineering department to our Chief Executive Officer; • review by our reservoir engineering department of all of our reported proved reserves at the close of each quarter, including the review of all significant reserve changes and all new proved undeveloped reserves additions; • provision of quarterly updates to our Board of Directors regarding operational data, including production, drilling and completion activity levels and any significant changes in our reserves; • annual review by our Board of Directors of our year-end reserve report and year-over-year changes in our proved reserves; • annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments, including the substitution, removal or deferral of PUD locations; and • annual review and approval by our senior management and our Board of Directors of a multi-year development plan. 6 Table of Contents Index to Financial Statements The tables below set forth information as of December 31, 2025, with respect to our estimated proved developed and undeveloped oil, natural gas and NGL reserves, the associated estimated future net revenue, the PV-10 and the standardized measure.
We focus on making substantive improvements to key areas that impact our employees. During 2024, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, 401(k) matches for eligible employees, and other enhancements to our benefits offerings.
We focus on making substantive improvements to key areas that impact our employees. During 2025, we continued making significant investments in our talent management and retention processes, including increasing funds allocated to annual salary increases, short-term incentive payments, long-term incentive equity awards, 401(k) matches for eligible employees, and other enhancements to our benefits offerings.
These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2024. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization.
These prices should not be interpreted as a prediction of future prices, nor do they reflect the value of our commodity derivative instruments in place as of December 31, 2025. The amounts shown do not give effect to non-property-related expenses, such as corporate general and administrative expenses and debt service, or to depreciation, depletion and amortization.
Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering. Michael Hodges, Executive Vice President and Chief Financial Officer On April 3, 2023, the Board of Directors appointed Mr. Hodges, 46, as Executive Vice President and Chief Financial Officer.
Reinhart began his career in the United States Army, serving tours in Panama and Iraq. Mr. Reinhart graduated from West Virginia University with a Bachelor of Science degree in Mechanical Engineering. Michael Hodges, Executive Vice President and Chief Financial Officer On April 3, 2023, the Board of Directors appointed Mr. Hodges, 47, as Executive Vice President and Chief Financial Officer.
Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs. We experienced total downward revisions of 406 Bcfe in estimated proved reserves.
Revisions represent changes in previous reserve estimates, either upward or downward, resulting from development plan changes, new information normally obtained from development drilling and production history or a change in economic factors, such as commodity prices, operating costs or development costs. We experienced total downward revisions of 38 Bcfe in estimated proved reserves.
Rucker, 39, joined Gulfport as the Senior Vice President of Operations in March 2023. On February 24, 2025, Matthew Rucker was promoted to Executive Vice President and Chief Operating Officer. He joined Gulfport from Javelin Energy Partners where he previously served as Vice President of Production Operations starting in August 2022. Mr.
Rucker, 40, joined Gulfport as the Senior Vice President of Operations in March 2023. On February 24, 2025, Matthew Rucker was promoted to Executive Vice President and Chief Operating Officer. He joined Gulfport from Javelin Energy Partners where he previously served as Vice President of Production Operations starting in August 2022. Mr.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2024, 2023 and 2022, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 of our consolidated financial statements.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2025, 2024 and 2023, and changes in proved reserves during the last three years are contained in the Supplemental Information on Oil and Gas Exploration and Production Activities, or Supplemental Information , in Note 20 of our consolidated financial statements.
Craine, 52, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr.
Craine, 53, has served as Chief Legal and Administrative Officer since June 2021 and joined Gulfport as Executive Vice President, General Counsel and Corporate Secretary in May 2019. Prior to joining the Company, Mr. Craine served as Deputy General Counsel – Chief Risk and Compliance Officer at Chesapeake Energy Corporation. Prior to joining Chesapeake in 2013, Mr.
Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 547 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage.
Extensions and discoveries. These are additions to our proved reserves that result from extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery. Extensions of approximately 701 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage.
Over the course of 2024, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations.
Over the course of 2025, Gulfport continued to develop and revise Company policies, including those intended to implement our Business Code of Conduct and Ethics, which provides a framework for how we interact with our employees, vendors and other stakeholders when conducting our operations.
Executive Officers John Reinhart, President, Chief Executive Officer and Director On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 56, as President, Chief Executive Officer and Director, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience.
Executive Officers John Reinhart, President, Chief Executive Officer and Director On January 18, 2023, the Board of Directors appointed Mr. Reinhart, 57, as President, Chief Executive Officer and Director, effective as of January 24, 2023. Mr. Reinhart joined the Company with over two decades of oil and gas industry leadership experience.
For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024.
For the purpose of determining prices used in our reserve reports, we used the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025.
We have approximately 208,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet. The Marcellus covers hydrocarbon-bearing rock formations that overlay the Utica.
We have approximately 223,000 net reservoir acres located primarily in Belmont, Harrison, Jefferson and Monroe Counties in eastern Ohio where the Utica ranges in thickness from 600 to over 750 feet. The Marcellus covers hydrocarbon-bearing rock formations that generally overlay the Utica in Ohio.
Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and letting some leases expire that are no longer part of our development plans.
Our leasehold management efforts include scheduling our operations to establish production in paying quantities in order to hold leases prior to the expiration dates, paying the prescribed lease extension payments, planning non-core divestitures or strategic acreage trades with other operators to high-grade our lease inventory and voluntarily allowing certain leases to expire that are no longer part of our development plans.
Our aggregate payments for the retainer and clean-up services during each of 2024, 2023 and 2022 were immaterial.
Our aggregate payments for the retainer and clean-up services during each of 2025, 2024 and 2023 were immaterial.
Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “ Risk Factors ” contained elsewhere in this Form 10-K.
Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. See Item 1A. “Risk Factors” contained elsewhere in this Form 10-K.
In the SCOOP, we intend to complete drilling on approximately two gross (1.8 net) operated horizontal wells and commence sales on two gross (1.8 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.
In the SCOOP, we intend to complete drilling and commence sales on approximately 2 gross (1.7 net) operated horizontal wells. We expect to fund these expenditures with our operating cash flow and borrowings under our Credit Facility.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2024, Grizzly had approximately 830,000 net acres under lease in the Athabasca, Peace River and Cold Lake oil sands regions of Alberta, Canada. Grizzly's operations have been suspended since 2015. Additionally, Grizzly had no proved reserves as of December 31, 2024.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2025, Grizzly had approximately 639,000 net acres under lease in the Athabasca, Peace River, and Cold Lake regions of Alberta, Canada. Grizzly's operations have been suspended since 2015. Additionally, Grizzly had no proved reserves as of December 31, 2025.
All PUD locations included in our 2024 reserve report are scheduled to be drilled within five years of initial booking. As of December 31, 2024, 1.20% of our total proved reserves were classified as proved developed non-producing.
All PUD locations included in our 2025 reserve report are scheduled to be drilled within five years of initial booking. As of December 31, 2025, 1.77% of our total proved reserves were classified as proved developed non-producing.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases (“GHG”). We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business.
Federal, state and local governments have periodically taken steps to reduce emissions of greenhouse gases (“GHG”). We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business.
The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During 2024, we produced approximately 212 MMcfe per day net to our interests in the SCOOP and it accounted for approximately 20% of our total production.
The primary targets are a series of porous, low clay and organic-rich packages within the Goddard Shale member ranging in thickness from 50 to over 250 feet. During 2025, we produced approximately 197 MMcfe per day net to our interests in the SCOOP and it accounted for approximately 19% of our total production.
The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $10 million as of December 31, 2024.
The present value of estimated future net revenue typically differs from the standardized measure because the former does not include the effects of estimated future income tax expense of $219 million as of December 31, 2025.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (BLM) or Bureau of Indian Affairs (BIA) of the Department of the Interior.
Certain of our U.S. natural gas and oil leases are granted or approved by the federal government and administered by the Bureau of Land Management (“BLM”) or Bureau of Indian Affairs (“BIA”) of the Department of the Interior.
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. 7 Table of Contents Index to Financial Statements The following table summarizes the changes in our estimated proved reserves during 2024 (in Bcfe): Proved Reserves, December 31, 2023 4,214 Sales of oil and natural gas reserves in place — Extensions and discoveries 547 Revisions of prior reserve estimates (406) Current production (386) Proved Reserves, December 31, 2024 3,969 Total may not sum due to rounding.
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. 7 Table of Contents Index to Financial Statements The following table summarizes the changes in our estimated proved reserves during 2025 (in Bcfe): Proved Reserves, December 31, 2024 3,969 Sales of oil and natural gas reserves in place — Extensions and discoveries 701 Revisions of prior reserve estimates (38) Current production (379) Proved Reserves, December 31, 2025 4,253 Total may not sum due to rounding.
Human Capital Management Employees As of December 31, 2024, we had 235 employees, an increase of approximately 4% from the 226 employees as of December 31, 2023. All of our employees are non-bargaining. The attraction and retention of qualified employees continues to be one of our highest priorities.
Human Capital Management Employees As of December 31, 2025, we had 245 employees, an increase of approximately 5% from the 235 employees as of December 31, 2024. All of our employees are non-bargaining. The attraction and retention of qualified employees continues to be one of our highest priorities.
Extensions and discoveries. Our extensions of approximately 547 Bcfe were primarily attributed to the addition of 62 PUD locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 46 PUD locations in the Utica/Marcellus and 16 PUD locations in the SCOOP. Conversion to proved developed reserves.
Extensions and discoveries. Our extensions of approximately 582 Bcfe were primarily attributed to the addition of 41 PUD locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 35 PUD locations in the Utica/Marcellus and 6 PUD locations in the SCOOP. Conversion to proved developed reserves.
See “ Definitions ” above for our definition of PV-10 (a non-GAAP financial measure) and “ Oil, Natural Gas and NGL Reserves and Estimation ” below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.
See “Definitions” above for our definition of PV-10 (a non-GAAP financial measure) and “Oil, Natural Gas and NGL Reserves and Estimation” below for a reconciliation of our standardized measure of discounted future net cash flows (the most directly comparable GAAP measure) to PV-10.
Major Customers Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, 2024, 2023 and 2022 were as follows: % of Sales Year Ended December 31, 2024 Vitol Inc. 15 % Year Ended December 31, 2023 Vitol Inc. 12 % Year Ended December 31, 2022 ECO-Energy 20 % Clearwater 11 % Competition The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have.
Major Customers Our total natural gas, oil and NGL sales, before the effects of hedging, to major customers (purchasers in excess of 10% of total natural gas, oil and NGL sales) for the years ended December 31, 2025, 2024 and 2023 were as follows: % of Sales Year Ended December 31, 2025 Customer A 14 % Year Ended December 31, 2024 Customer A 15 % Year Ended December 31, 2023 Customer A 12 % Competition The oil and natural gas industry is intensely competitive, and we compete with many other companies that have greater resources than we have.
These downward revisions were offset by upward revisions of 116 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest and well forecasts. Costs incurred relating to the development of PUDs were approximately $326.4 million in 2024.
These downward revisions were offset by upward revisions of 89 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest, well forecasts and price changes. Costs incurred relating to the development of PUDs were approximately $235.9 million in 2025.
We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans. 2025 Outlook Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million.
We believe our plan to generate free cash flow on an annual basis will allow us to further strengthen our balance sheet, return capital to shareholders and increase our resource depth through incremental leasehold opportunities that provide optionality to our future development plans. 2026 Outlook Our 2026 capital expenditure program is expected to be in a range of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments.
PV-10 Sensitivities As noted above, our proved reserves at December 31, 2024, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2024 of $76.32 per barrel and $2.13 per MMBtu.
PV-10 Sensitivities As noted above, our proved reserves at December 31, 2025, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2025 of $66.01 per barrel and $3.39 per MMBtu.
The prices used in our PV-10 measure were the average WTI Spot price of $76.32 per barrel and the average Henry Hub Spot price of $2.13 per MMBtu, before basis differential adjustments.
The prices used in our PV-10 measure were the average WTI Spot price of $66.01 per barrel and the average Henry Hub Spot price of $3.39 per MMBtu, before basis differential adjustments.
As needed, we provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits. Reserve estimates for the years ended 2023 and 2022, were prepared by NSAI for 100% of our operating areas.
As needed, we provide historical information to NSAI for our properties such as ownership interest, oil and gas production, well test data, commodity prices, operating and development costs and other considerations, including availability and costs of infrastructure and status of permits.
December 31, 2024 Proved Developed Proved Undeveloped Total Proved ($ in millions) Estimated future net revenue (1) $ 1,620 $ 1,876 $ 3,496 Present value of estimated future net revenue (PV-10) (1) $ 1,059 $ 699 $ 1,757 Standardized measure (1) $ 1,747 Totals may not sum due to rounding. _____________________ (1) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2024, and assuming commodity prices as set forth below.
December 31, 2025 Proved Developed Proved Undeveloped Total Proved ($ in millions) Estimated future net revenue (1) $ 3,816 $ 3,145 $ 6,961 Present value of estimated future net revenue (PV-10) (1) $ 2,291 $ 1,331 $ 3,622 Standardized measure (1) 3,403 Totals may not sum due to rounding. _____________________ (1) Estimated future net revenue represents the estimated future revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs under existing economic conditions as of December 31, 2025, and assuming commodity prices as set forth below.
Holding production and development costs constant, if SEC pricing were $83.95 per barrel and $2.34 per MMBtu, or a 10% increase, this would have resulted in an increase of 87 Bcfe of our total proved reserves and a $0.54 billion increase in PV-10 value at December 31, 2024.
Holding production and development costs constant, if SEC pricing were $72.61 per barrel and $3.73 per MMBtu, or a 10% increase, this would have resulted in an increase of 38 Bcfe of our total proved reserves and a $0.77 billion increase in PV-10 value at December 31, 2025.
ITEM 1. BUSINESS Our Business Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations.
ITEM 1. BUSINESS Our Business Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins. Our principal operations target the Utica and Marcellus formations in eastern Ohio and the SCOOP Woodford and Springer formations in central Oklahoma. Gulfport's Predecessor was incorporated in the State of Delaware in July 1997.
Holding production and development costs constant, if SEC pricing were $68.69 per barrel and $1.92 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 494 Bcfe of our total proved reserves and a $0.51 billion decrease in PV-10 value at December 31, 2024.
Holding production and development costs constant, if SEC pricing were $59.41 per barrel and $3.05 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 54 Bcfe of our total proved reserves and a $0.77 billion decrease in PV-10 value at December 31, 2025.
Our 2024 development activities resulted in the conversion of approximately 341 Bcfe into proved developed producing reserves, attributable to 16 PUD locations in the Utica and 5 PUD locations in the SCOOP. These 21 PUDs represent a conversion rate of 13% for 2024. Revision of prior reserve estimates.
Our 2025 development activities resulted in the conversion of approximately 417 Bcfe into proved developed producing reserves, attributable to 31 PUD locations in the Utica/Marcellus and 11 PUD locations in the SCOOP. These 42 PUDs represent a conversion rate of 28% for 2025. Revision of prior reserve estimates.
Year Ended December 31, 2024 2023 2022 Gross Net Gross Net Gross Net Development: Productive 21 19.8 24 21.9 25 21.7 Dry — — — — — — Total 21 19.8 24 21.9 25 21.7 Exploratory: Productive — — — — — — Dry — — — — — — Total — — — — — — The following table presents activity by operating area for the year ended December 31, 2024: Operated Non-Operated Field Drilled Turned to Sales Drilled Turned to Sales Gross Net Gross Net Gross Net Gross Net Utica & Marcellus (1) 18.0 17.4 16.0 15.4 16.0 0.1 8.0 0.1 SCOOP (2) 3.0 2.4 3.0 2.4 18.0 0.2 16.0 0.1 Total 21.0 19.8 19.0 17.8 34.0 0.3 24.0 0.2 _____________________ (1) Of the 18 gross wells drilled in 2024, 10 were completed as producing wells and eight were in various stages of drilling and completion as of December 31, 2024.
Year Ended December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Development: Productive 29 28.7 21 19.8 24 21.9 Dry — — — — — — Total 29 28.7 21 19.8 24 21.9 Exploratory: Productive — — — — — — Dry — — — — — — Total — — — — — — The following table presents activity by operating area for the year ended December 31, 2025: Operated Non-Operated Field Drilled Turned to Sales Drilled Turned to Sales Gross Net Gross Net Gross Net Gross Net Utica & Marcellus (1) 27.0 26.9 30.0 30.0 8.0 0.1 14.0 0.0 SCOOP (2) 2.0 1.8 2.0 1.8 18.0 0.1 23.0 0.2 Total 29.0 28.7 32.0 31.8 26.0 0.2 37.0 0.2 _____________________ (1) Of the 27 gross operated wells drilled in 2025, 22 were completed as producing wells and five were in various stages of drilling and completion as of December 31, 2025.
In the Utica, we intend to complete drilling on approximately 17 gross (17.0 net) operated horizontal wells and commence sales on approximately 22 gross (21.9 net) operated horizontal wells. In the Marcellus, we intend to complete drilling on approximately 8 gross (8.0 net) operated horizontal wells and commence sales on approximately 4 gross (4.0 net) operated horizontal wells.
In the Utica, we intend to complete drilling on approximately 18 gross (17.5 net) operated horizontal wells and commence sales on approximately 20 gross (19.5 net) operated horizontal wells. In the Marcellus, we intend to complete drilling on approximately 6 gross (5.6 net) and commence sales on approximately 4 gross (4.0 net) operated horizontal wells.
Proved Undeveloped Reserves As of December 31, 2024, our PUDs totaled 1,478 Bcf of natural gas, 15 MMBbl of oil and 49 MMBbl of NGL, for a total of 1,861 Bcfe. Approximately 80% and 20% of our PUD reserves at year-end 2024 were located in Utica/Marcellus and SCOOP, respectively.
Proved Undeveloped Reserves As of December 31, 2025, our PUDs totaled 1,455 Bcf of natural gas, 16 MMBbl of oil and 50 MMBbl of NGL, for a total of 1,848 Bcfe. Approximately 82% and 18% of our PUD reserves at year-end 2025 were located in Utica/Marcellus and SCOOP, respectively.
During 2024, we repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share, leaving $415.9 million remaining on our Repurchase Program, which expires on December 31, 2025. Operating Areas Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada.
D uring 2025, we repurchased 1.8 million shares for $336.3 million at a weighted average price of $188.65 per share, leaving $579.6 million remaining on our Repurchase Program, which expires on December 31, 2026. Operating Areas Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada.
Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates. Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates. He is a petroleum engineer with over 28 years of reservoir and operations experience.
Refer to Note 20 of our consolidated financial statements for more information pertaining to our proved reserves and the preparation of such estimates. 5 Table of Contents Index to Financial Statements Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates.
After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved.
The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time. After a development plan has been adopted, we may periodically make adjustments to the approved development plan due to events and circumstances that have occurred subsequent to the time the plan was approved.
The executive officers serve at the pleasure of the Company's Board of Directors. 19 Table of Contents Index to Financial Statements
Each executive officer serves at the discretion of the Board of Directors. 19 Table of Contents Index to Financial Statements
We cannot predict with any reasonable degree of certainty our future exposure concerning such matters. 15 Table of Contents Index to Financial Statements Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties.
See the “Risk Factors” described in Item 1A of this report for further discussion of governmental regulation and ongoing regulatory changes, including with respect to environmental matters. 15 Table of Contents Index to Financial Statements Our operations are also subject to conservation regulations, including the regulation of the size of drilling and spacing units or proration units, the number of wells that may be drilled in a unit, the rate of production allowable from oil and gas wells, and the unitization or pooling of oil and gas properties.
We have approximately 73,000 net reservoir acres (comprised of approximately 43,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties.
The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations. We have approximately 74,000 net reservoir acres (comprised of approximately 44,000 in the Woodford formation and approximately 30,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties.
He holds a degree in Mineral Land Management from the University of Evansville. Mr. Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America. There is no family relationship between any of our officers or between any of them and the Company's Board of Directors.
Zitkus is a member of the American Association of Professional Landmen and Past Regional Director of the Independent Petroleum Association of America. There are no family relationships among our executive officers or between any executive officer and any member of the Board of Directors.
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.
Commodity prices experienced volatility throughout 2025 and the 12-month unweighted average of the 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.
We expect this drilling program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025. 4 Table of Contents Index to Financial Statements Additionally, in 2025, we expect a continuation of shareholder return actions through our Repurchase Program.
We expect this development program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026. 4 Table of Contents Index to Financial Statements Additionally, in 2026, we expect to continue returning capital to shareholders through our Repurchase Program.
Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders. To accomplish these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
To achieve these goals, we generally allocate capital to projects we believe offer the highest rate of return and we deploy leading drilling and completion techniques and technologies in our development efforts.
These circumstances may include changes in commodity price outlook and costs, delays in the availability of infrastructure, well permitting delays and new data from recently completed wells. 8 Table of Contents Index to Financial Statements The following table summarizes the changes in our estimated proved undeveloped reserves during 2024 (in Bcfe): Proved Undeveloped Reserves, December 31, 2023 2,011 Sales of oil and natural gas reserves in place — Extensions and discoveries 547 Conversion to proved developed reserves (341) Revisions of prior reserve estimates (357) Proved Undeveloped Reserves, December 31, 2024 1,861 Total may not sum due to rounding.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2025 (in Bcfe): Proved Undeveloped Reserves, December 31, 2024 1,861 Sales of oil and natural gas reserves in place — Extensions and discoveries 582 Conversion to proved developed reserves (417) Revisions of prior reserve estimates (177) Proved Undeveloped Reserves, December 31, 2025 1,848 Total may not sum due to rounding.
We experienced total downward revisions of 357 Bcfe in estimated proved undeveloped reserves. This included 300 Bcfe of downward revisions associated with commodity price changes.
We experienced total downward revisions of 177 Bcfe in estimated proved undeveloped reserves. This included 182 Bcfe and 84 Bcfe of downward revisions associated with changes in our development schedule changes and PUD well design changes, respectively.
We have identified approximately 20,500 net reservoir acres of our existing leasehold for Marcellus development and have 22 PUD Marcellus locations within our Utica operating area. In 2023 we drilled, completed, and turned to sales two Marcellus wells and have plans to drill eight Marcellus wells and complete and turn to sales four Marcellus wells in 2025.
We have identified approximately 35,000 net reservoir acres of our existing leasehold for Marcellus development and have 25 PUD Marcellus locations. In 2025 we drilled, completed, and turned to sales our first four well development pad in the Marcellus. Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica.
These consisted of upward revisions of 16 Bcfe as a result of positive well performance and 171 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 488 Bcfe which were associated with commodity price changes.
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.
Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013. During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007.
During his 20-year tenure with Equitable Resources Inc. (now EQT Corp.), he held various positions, including Vice President of Operations and Senior Vice President of Land, between 1987 and 2007. He holds a degree in Mineral Land Management from the University of Evansville. Mr.
In the course of its audit, NSAI conducted a detailed review of properties making up approximately 85% of the total proved reserves and accounting for approximately 95% of the present worth of those reserves.
NSAI is an independent petroleum engineering firm and was selected for their historical experience and geographic expertise in engineering similar resources. In the course of its audit, NSAI conducted a detailed review of properties making u p approximately 86% of the total proved reserves and accounting for approximately 88% of the present worth of those reserves.
Gulfport's Predecessor was incorporated in the State of Delaware in July 1997. Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (NYSE) under the ticker symbol “GPOR”.
Our corporate headquarters are located in Oklahoma City, Oklahoma and shares of Gulfport's common stock trade on the New York Stock Exchange (“NYSE”) under the ticker symbol “GPOR”. Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow.
For the low price scenario 128 PUDs were PV-10 economic. 9 Table of Contents Index to Financial Statements Acreage The following table presents our total gross and net developed and undeveloped acres as of December 31, 2024: Developed Acreage Undeveloped Acreage Field Gross Net Gross Net Utica & Marcellus 161,391 133,638 77,387 74,359 SCOOP 49,922 35,896 9,829 7,134 Total 211,313 169,534 87,216 81,493 Of our leases that are not held by production, most have a five-year primary term, many of which include options to extend the primary term.
For the low price scenario 132 PUDs were PV-10 economic. 9 Table of Contents Index to Financial Statements Acreage The following table presents our total gross and net developed and undeveloped acres as of December 31, 2025: Developed Acreage Undeveloped Acreage Field Gross Net Gross Net Utica & Marcellus 170,209 142,239 83,069 80,294 SCOOP 50,735 36,174 10,689 7,680 Total 220,944 178,413 93,758 87,974 Of our leases that are not held by production or held by other applicable lease provisions, most have a five-year primary term, and many include an optional right to extend the primary term for an additional three or five years.
The Chapter 11 Cases were administered jointly under the caption In re Gulfport Energy Corporation, et al., Case No. 20-35562 (DRJ). The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date.
The Bankruptcy Court confirmed the Plan and entered the confirmation order on April 28, 2021, and the Debtors emerged from the Chapter 11 Cases on the Emergence Date. On May 18, 2021, we began trading on the NYSE under the symbol “GPOR”.
Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves.
Our PUDs will be converted from undeveloped to developed as the applicable wells commence production or when there are no material incremental completion capital expenditures associated with such proved developed reserves. 8 Table of Contents Index to Financial Statements We record PUD locations only after a development plan has been approved by our senior management and Board of Directors to complete the associated development drilling within five years from the time of initial booking.
Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica. During 2024, we produced approximately 842 MMcfe per day net to our interests in Utica/Marcellus and it accounted for approximately 80% of our total production.
During 2025, we produced approximately 841 MMcfe per day net to our interests in Utica/Marcellus and it accounted for approximately 81% of our total production. SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin.
In addition, our geoscience staff has approximately 51 years combined industry experience and our reservoir staff has approximately 61 years combined experience. 5 Table of Contents Index to Financial Statements During 2024, our total net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by our engineers and Netherland, Sewell & Associates, Inc.
During 2025, our total net natural gas, NGLs and oil proved reserves estimates attributable to the Company's interests were prepared by the Company and Netherland, Sewell & Associates, Inc. (“NSAI”) conducted an audit of the proved reserves as of December 31, 2025.
Sluiter is a graduate of the University of Sydney, Australia, with a Bachelor of Science degree in Chemical Engineering. Lester Zitkus, Senior Vice President of Land Mr. Zitkus, 59, has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr.
Zitkus, 60, has served as Senior Vice President of Land since January 2017 and joined the Company as Vice President of Land in March 2014. Prior to joining the Company, Mr. Zitkus served as an independent consultant from October 2013 to March 2014 and as Vice President of Land for Chesapeake Energy Corporation from May 2007 to October 2013.
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.
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.
On May 18, 2021, we began trading on the NYSE under the symbol “ GPOR ” . Business Strategy Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica/Marcellus and SCOOP operating areas.
Business Strategy Gulfport aims to create sustainable value through the economic development of our significant resource plays in the Utica/Marcellus and SCOOP operating areas. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, enhancing margins and operating efficiencies and returning capital to shareholders.
We added 46 PUD locations in the Utica/Marcellus which included 33 Utica locations for 341 Bcfe and 13 Marcellus locations for 92 Bcfe. In the SCOOP, we added 16 PUD locations for 114 Bcfe. Revisions of prior reserve estimates.
We added 35 PUD locations in the Utica/Marcellus which included 28 Utica locations for 382 Bcfe and 7 Marcellus locations for 62 Bcfe. We also added 11 operated locations in the Utica to PDP which were not previously booked for 119 Bcfe. In the SCOOP, we added 6 PUD locations for 138 Bcfe. Revisions of prior reserve estimates.
Additionally, downward revisions of 172 Bcfe were associated with changes in our development schedule. The schedule changes moved the development of 11 Utica/Marcellus PUD locations and 6 SCOOP PUD locations beyond the SEC requirement of developing PUDs five years from initial booking.
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.
December 31, 2024 Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Total (Bcfe) Utica & Marcellus Proved developed (1) 4 1,427 8 1,498 Proved undeveloped (1) 13 1,189 36 1,480 Total proved (1) 17 2,616 44 2,978 SCOOP Proved developed 4 451 23 611 Proved undeveloped 2 289 13 380 Total proved 5 740 36 991 Total Proved developed 7 1,879 31 2,109 Proved undeveloped 15 1,478 49 1,861 Total proved 22 3,356 80 3,969 Totals may not sum or recalculate due to rounding. _____________________ (1) Includes approximately 12 Bcfe and 174 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.
December 31, 2025 Oil (MMBbl) Natural Gas (Bcf) NGL (MMBbl) Total (Bcfe) Utica & Marcellus Proved developed (1) 4 1,717 12 1,818 Proved undeveloped (1) 14 1,189 39 1,510 Total proved (1) 19 2,906 52 3,328 SCOOP Proved developed 4 440 21 587 Proved undeveloped 2 266 10 338 Total proved 5 707 31 925 Total Proved developed 8 2,157 33 2,404 Proved undeveloped 16 1,455 50 1,848 Total proved 24 3,612 83 4,253 Totals may not sum or recalculate due to rounding. _____________________ (1) Includes approximately 26 Bcfe and 210 Bcfe of net developed and undeveloped reserves, respectively, located in the Marcellus target formation.
The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2024: Undeveloped Acres Years Ending December 31, Gross Acres Net Acres 2025 2,203 2,195 2026 3,682 3,661 2027 2,812 2,775 After 2027 18,673 18,667 Held by production 59,846 54,195 Total 87,216 81,493 Productive Wells The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2024: NRI/WI Productive Oil Wells Productive Gas Wells Total Wells Field Percentages Gross Net Gross Net Gross Net Utica & Marcellus 49.66/60.84 15 5.15 712 437.2 727 442.4 SCOOP 21.41/26.49 119 12.23 531 159.92 650 172.1 Total (1) 143 17.4 1,411 597.1 1,554 614.5 _____________________ (1) We also have override/royalty interests in 177 wells with an average NRI of 0.6%, which are not material to our operations.
The following table sets forth the potential expiration periods of gross and net undeveloped leasehold acres as of December 31, 2025: Undeveloped Acres Gross Acres Net Acres 2026 2,827 2,806 2027 1,672 1,636 2028 10,048 10,042 After 2028 19,930 19,930 Held by production 59,281 53,560 Total 93,758 87,974 Productive Wells The following table presents our total gross and net productive wells, expressed separately for oil and gas, as of December 31, 2025: NRI/WI Productive Oil Wells Productive Gas Wells Total Wells Field Percentages Gross Net Gross Net Gross Net Utica & Marcellus 50.25/61.58 69 25.5 697 446.2 766 471.7 SCOOP 20.86/25.82 129 13.3 518 153.8 647 167.1 Total (1) 215 38.8 1,380 600.0 1,595 638.8 _____________________ (1) We also have override/royalty interests in 182 wells with an average NRI of 0.6%, which are not material to our operations.
Internal Controls Over Proved Reserve Estimates Our proved reserve estimates are prepared in accordance with our internal control procedures.
Reserve estimates for the year ended 2024 were prepared by the Company and audited by NSAI as of December 31, 2024. Reserve estimates for the year ended 2023 were prepared by NSAI for 100% of our operating areas. Internal Controls Over Proved Reserve Estimates Our proved reserve estimates are prepared in accordance with our internal control procedures.
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 67 Bcfe were a result of a combination of various economic assumption updates.
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.
Sluiter, 52, joined Gulfport as the Senior Vice President of Reservoir Engineering in December 2018 from Noble Energy, Inc., where he most recently served as the Permian Basin Business Unit Manager.
Sluiter, 53, joined Gulfport in December 2018 from Noble Energy, Inc., where he held various engineering and leadership positions from March 2007 to November 2018, including Permian Basin Business Unit Manager, Appalachian Reservoir Engineering Supervisor, and Business Development Engineering Advisor. Prior to joining Noble Energy, Mr.
Our corporate strategy is focused on the economic development of our asset base in an effort to generate sustainable free cash flow. As of December 31, 2024, we had 4.0 Tcfe of proved reserves with a Standardized Measure of $1.75 billion and a PV-10 of $1.76 billion.
As of December 31, 2025, we had 4.3 Tcfe of proved reserves with a Standardized Measure of $3.4 billion and a PV-10 of $3.6 billion.
Additionally, downward revisions of 172 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 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.
Removed
SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations.
Added
He is a petroleum engineer with 30 years of reservoir and operations experience. In addition, our geoscience staff has approximately 58 years combined industry experience and our reservoir staff also has approximately 58 years combined experience.
Removed
(“NSAI”) conducted an audit of the proved reserves as of December 31, 2024. NSAI is an independent petroleum engineering firm and were selected for their historical experience and geographic expertise in engineering similar resources.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

53 edited+12 added−10 removed183 unchanged
Biggest changeOur performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees. Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished.
Biggest changeOur ability to respond to these changes in a timely and cost efficient manner is uncertain, and if technologies we rely on become obsolete, our business, financial condition, or results of operations could be materially and adversely affected. 23 Table of Contents Index to Financial Statements Our performance depends largely on the talents and efforts of highly skilled individuals and on our ability to attract new employees and to retain and motivate our existing employees.
Our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to: • unexpected drilling conditions, pressure conditions or irregularities in reservoir formations; • loss of drilling fluid circulation; • equipment failures or accidents; • fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals; • risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground migration of fracturing fluids, including chemical additives; 26 Table of Contents Index to Financial Statements • adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures, which may be exacerbated by climate change; • issues with title or in receiving governmental permits or approvals; • restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets; • environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us; • restrictions in access to, or disposal of, water used or produced in drilling and completion operations; • shortages or delays in the availability of services or delivery of equipment; and • unexpected or unforeseen changes in regulatory policy, and political or public opinions.
Our oil and gas properties can become damaged, our operations may be curtailed, delayed or canceled and the costs of such operations may increase as a result of a variety of factors, including, but not limited to: • unexpected drilling conditions, pressure conditions or irregularities in reservoir formations; • loss of drilling fluid circulation; • equipment failures or accidents; • fires, explosions, blowouts, cratering or loss of well control, as well as the mishandling or underground migration of fluids and chemicals; • risks associated with hydraulic fracturing, including any mishandling, surface spillage or potential underground 26 Table of Contents Index to Financial Statements migration of fracturing fluids, including chemical additives; • adverse weather conditions and natural disasters, such as tornadoes, earthquakes, hurricanes and extreme temperatures, which may be exacerbated by climate change; • issues with title or in receiving governmental permits or approvals; • restricted takeaway capacity for our production, including due to inadequate midstream infrastructure or constrained downstream markets; • environmental hazards or liabilities, including liabilities for environmental damage caused by previous owners of properties purchased by us; • restrictions in access to, or disposal of, water used or produced in drilling and completion operations; • shortages or delays in the availability of services or delivery of equipment; and • unexpected or unforeseen changes in regulatory policy, and political or public opinions.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including: • domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves; • the level of prices, and expectations about future prices, of oil and natural gas; • changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns, such as the recent coronavirus; • the cost of exploring for, developing, producing and delivering oil and natural gas; • the expected rates of declining current production; • the price and availability of alternative fuels; • technological advances and changing consumer attitudes affecting energy consumption; • risks associated with operating drilling rigs; • the effectiveness of worldwide conservation measures; • the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities; • the level and effect of trading in commodity futures markets, including by commodity price speculators and others; • U.S. exports of oil, natural gas, liquefied natural gas and NGL; • the price and level of foreign imports and exports, including as a result of U.S. trade policy; • the nature and extent of domestic and foreign governmental regulations and taxes; • the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls; • political or economic instability or armed conflict in oil and natural gas producing regions; • weather conditions; • acts of terrorism; and • domestic and global economic conditions. 20 Table of Contents Index to Financial Statements These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty.
Wide fluctuations in natural gas, oil and NGL prices may result from factors that are beyond our control, including: • domestic and worldwide supplies of oil, natural gas and NGL, including U.S. inventories of oil and natural gas reserves; • the level of prices, and expectations about future prices, of oil and natural gas; • changes in the level of consumer and industrial demand, including impacts from global or national health epidemics and concerns; • the cost of exploring for, developing, producing and delivering oil and natural gas; • the expected rates of declining current production; • the price and availability of alternative fuels; • technological advances and changing consumer attitudes affecting energy consumption; • risks associated with operating drilling rigs; • the effectiveness of worldwide conservation measures; • the availability, proximity and capacity of pipelines, other transportation facilities and processing facilities; • the level and effect of trading in commodity futures markets, including by commodity price speculators and others; • U.S. exports of oil, natural gas, liquefied natural gas and NGL; • the price and level of foreign imports and exports, including as a result of U.S. trade policy; • the nature and extent of domestic and foreign governmental regulations and taxes; • the ability of the members of the Organization of Petroleum Exporting Countries and others to agree to and maintain oil price and production controls; • political or economic instability or armed conflict in oil and natural gas producing regions; • weather conditions; • acts of terrorism; and • domestic and global economic conditions. 20 Table of Contents Index to Financial Statements These factors and the volatility of the energy markets make it extremely difficult to predict future natural gas, oil and NGL price movements with any certainty.
Although we seek to actively manage our undeveloped properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
Although we seek to actively manage our undeveloped leasehold properties, our drilling plans for these areas are subject to change based upon various factors, including drilling results, oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, gathering system and pipeline transportation constraints and regulatory approvals.
Endangered Species. The Endangered Species Act (ESA) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA.
Endangered Species. The Endangered Species Act (“ESA”) prohibits the taking of endangered or threatened species or their habitats. While some of our assets and lease acreage may be located in areas that are designated as habitats for endangered or threatened species, we believe that we are in material compliance with the ESA.
In highly competitive markets for acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
In highly competitive markets for leasehold acreage, failure to drill sufficient wells to hold acreage could result in a substantial lease renewal cost or, if renewal is not feasible, loss of our lease and prospective drilling opportunities.
A failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for ESG issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.
A failure to comply with investor or customer expectations and standards, which are evolving, or if we are perceived to not have responded appropriately to the growing concern for sustainability issues, regardless of whether there is a legal requirement to do so, could cause reputational harm to our business, increase our risk of litigation, and could have a material adverse effect on our results of operations.
If we are unable to meet the ESG standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for ESG-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.
If we are unable to meet the sustainability standard or investment, lending, ratings, or voting criteria and policies set by these parties, we may lose investors, investors may allocate a portion of their capital away from us, we may become a target for sustainability-focused activism, our cost of capital may increase, the price of our securities may be negatively impacted, and our reputation may also be negatively affected.
For example, in March 2024, the United States Environmental Protection Agency (USEPA), issued its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 (“IRA 2022”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities, the rule for which was finalized in November 2024.
For example, in March 2024, the United States Environmental Protection Agency (“USEPA”) issued its final methane rules to reduce methane emissions from both new and existing oil and natural gas facilities and the Inflation Reduction Act of 2022 (“IRA 2022”) established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities, the rule for which was finalized in November 2024.
In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 86% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration.
In addition, many of our oil and natural gas leases require us to drill wells that are commercially productive, and if we are unsuccessful in drilling such wells, we could lose our rights under such leases. Although approximately 84% of our Utica/Marcellus acreage is held by existing production, the remaining acreage is subject to expiration.
In the state of Ohio, all water used during drilling operations is disposed of through injection into third-party salt water disposal wells regulated by applicable state agencies. Increased attention to ESG matters may impact our business, financial results, or stock price.
In the state of Ohio, all water used during drilling operations is disposed of through injection into third-party salt water disposal wells regulated by applicable state agencies. Increased attention to sustainability matters may impact our business, financial results, or stock price.
In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Code) at any time during a rolling three-year period.
In general, an ownership change will occur if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code) at any time during a rolling three-year period.
We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2024, our aggregate long-term contractual obligation under these agreements was approximately $1.1 billion.
We have contracts with some of our third-party service providers for gathering, processing and transportation services with minimum volume delivery commitments under which we are obligated to pay certain fees on minimum volumes regardless of actual volume throughput. As of December 31, 2025, our aggregate long-term contractual obligation under these agreements was approximately $1.0 billion.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to ESG matters. These ratings are used by some investors to inform their investment and voting decisions.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings systems for evaluating companies on their approach to sustainability matters. These ratings are used by some investors to inform their investment and voting decisions.
A cyberattack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or royalty owners’ data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
A cyberattack involving our information systems and related infrastructure, or that of our business associates, could result in supply chain disruptions that delay or prevent the transportation and marketing of our production, non-compliance leading to regulatory fines or penalties, loss or disclosure of, or damage to, our or any of our customers’, suppliers’ or royalty owners' data or confidential information that could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
Unfavorable ESG ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
Unfavorable sustainability ratings may lead to increased negative investor sentiment toward us and our industry and to the diversion of investment to other industries, which could have a negative impact on our stock price and our access to and costs of capital.
If this purchaser or one or more other significant purchasers, are unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable.
If this purchaser or one or more other significant purchasers, is unable to satisfy its contractual obligations, we may be unable to sell such production to other customers on terms we consider acceptable.
Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop the related properties. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all.
Low commodity prices may cause us to delay our drilling plans and, as a result, lose our right to develop certain leases. The cost to renew expiring leases may increase significantly, and we may not be able to renew such leases on commercially reasonable terms or at all.
We may take certain actions to improve the ESG profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect.
We may take certain actions to improve the sustainability profile of our company and/or products, but we cannot guarantee that such actions will have the desired effect.
In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. As of December 31, 2024, approximately 47% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced.
In addition, we may adjust estimates of proved reserves to reflect production history, results of exploration and development drilling, prevailing oil and natural gas prices and other factors, many of which are beyond our control. As of December 31, 2025, approximately 43% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced.
Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting oil and NGL to one Mcf of natural gas at the ratio of six Mcf of natural gas to one barrel of oil.
Such capitalized costs, including the estimated future development costs and site remediation costs, if any, are depleted by an equivalent units-of-production method, converting oil and NGL barrels to gas equivalents at the ratio of one barrel to six Mcf of gas.
In addition, we note that standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reducing emissions may be, either currently by some stakeholders or at some future point, considered inconsistent with common or best practices.
Standards and expectations regarding carbon accounting and the processes for measuring and counting GHG emissions and GHG emission reductions are evolving, and it is possible that our approach to measuring both our emissions and our approaches to reducing emissions may be, either currently by some stakeholders or at some future point, considered inconsistent with common or best practices.
For example, the California Consumer Privacy Act (CCPA), as amended by the California Privacy Rights Act (CPRA), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties.
For example, the California Consumer Privacy Act (“CCPA”), as amended by the California Privacy Rights Act (“CPRA”), establishes certain transparency rules and creates new data privacy rights for individuals, including limitations on our use of certain sensitive personal information and more ability for individuals to control the purposes for which their data is shared with third parties.
Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2025 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2025 and beyond.
Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our future cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2026 and beyond.
Further, the Bureau for Land Management (BLM) issued a final Methane Waste Prevention Rule on April 10, 2024. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions.
Further, the BLM issued a final Methane Waste Prevention Rule on April 10, 2024. The rule adds additional requirements for operators on federal and Indian leases and includes new air quality requirements along with waste prevention provisions.
Governments may continue to study hydraulic fracturing. We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities.
We cannot predict the outcome of future studies, but based on the results of these studies to date, federal and state legislatures and agencies may seek to further regulate or even ban hydraulic fracturing activities.
Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future. Our undeveloped acreage must be drilled before lease expiration to hold the acreage by production.
Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline in the future. Our undeveloped leasehold acreage must be drilled before the lease's expiration date in order to hold the lease by production.
During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. 23 Table of Contents Index to Financial Statements The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
During these periods, there is often a shortage of drilling rigs and other oilfield equipment and services, which could adversely affect our ability to execute our development plans on a timely basis and within budget. The actual quantities of and future net revenues from our proved reserves may be less than our estimates.
Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantial capital expenditures are required to develop such reserves. Estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated.
Recovery of PUDs requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports audited by an independent petroleum engineering firm assume that substantial capital expenditures are required to develop such reserves. Estimated development costs may not equal our actual costs, development may not occur as scheduled and results may not be as estimated.
As of December 31, 2024, we did not hedge our interest rate risk. 21 Table of Contents Index to Financial Statements Our debt and other financial commitments may limit our financial and operating flexibility. Our total principal debt was approximately $713.7 million at December 31, 2024.
As of December 31, 2025, we did not hedge our interest rate risk. 21 Table of Contents Index to Financial Statements Our debt and other financial commitments may limit our financial and operating flexibility. Our total principal debt was approximately $797.0 million at December 31, 2025.
As of December 31, 2024, we had a net operating loss, or NOL, carryforward of approximately $1.6 billion for federal income tax purposes.
As of December 31, 2025, we had a net operating loss, or NOL, carryforward of approximately $1.5 billion for federal income tax purposes.
If we are unable to fund renewals of expiring leases, we could lose portions of our acreage and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. Oil and natural gas operations are uncertain and involve substantial costs and risks.
If we are unable to fund the cost of renewing expiring leases, portions of our leasehold acreage could expire and our actual drilling activities may differ materially from our current expectations, which could adversely affect our business. Oil and natural gas operations are uncertain and involve substantial costs and risks.
The largest purchaser of our oil and natural gas during the year ended December 31, 2024, accounted for approximately 15% of our total natural gas, oil and NGL revenues.
The largest purchaser of our oil and natural gas during the year ended December 31, 2025, accounted for approximately 14% of our total natural gas, oil and NGL revenues.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established.
Leases on oil and natural gas properties typically have a term of three to five years, after which they expire unless a lease contains an optional right to extend its term or, prior to expiration, a well is drilled and production of hydrocarbons in paying quantities is established.
The December 31, 2024 present value is based on a $2.13 per MMBtu of gas price and a $76.32 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
The December 31, 2025 present value is based on a $3.39 per MMBtu of gas price and a $66.01 per Bbl of oil price, before considering basis differential adjustments. Actual future prices and costs may be materially higher or lower than the prices and costs as of the date of an estimate.
For the year ended December 31, 2024, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 8.23%. A 1% increase in the average interest rate would increase our interest expense by approximately $0.4 million based on outstanding borrowings under our Credit Facility at December 31, 2024.
For the year ended December 31, 2025, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 6.53%. A 1% increase in the average interest rate would increase our interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2025.
The Pipeline and Hazardous Materials Safety Administration (PHMSA) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas”.
The Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a series of rules that require pipeline operators to develop and implement integrity management programs for gas, NGL and condensate transmission pipelines as well as certain low stress pipelines and gathering lines transporting hazardous liquids, such as oil, that, in the event of a failure, could affect “high consequence areas.” Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas.
Of the remaining 14% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in 2025, 12% in 2026, 9% in 2027 and approximately 72% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend these leases for an additional three or five-year period.
Of the remaining 16% of our Utica/Marcellus acreage not held by production, approximately 7% will be subject to expiration in 2026, 4% in 2027, 28% in 2028 and approximately 61% thereafter, although a portion of our Utica/Marcellus leases generally grant us the right to extend the term for an additional three or five-year period.
As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power.
As a result, these competitors may be able to address these competitive factors more effectively or weather industry downturns more easily than we can. We also face indirect competition from alternative energy sources, including wind, solar and electric power. In addition, the oil and gas industry is characterized by rapid technological change and the introduction of new products and services.
For example, during 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu.
For example, during 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu.
For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities.
Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry. For example, the OCC issued guidance to operators in the SCOOP and STACK areas for management of certain seismic activity that may be related to hydraulic fracturing or water disposal activities.
In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels. 32 Table of Contents Index to Financial Statements In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.
In addition, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.
Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time.
Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs. Renewable energy standards (also referred to as renewable portfolio standards) require electric utilities to provide a specified minimum percentage of electricity from eligible renewable resources, with potential increases to the required percentage over time.
In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing.
Several states including New York, Maryland and Vermont, have banned or imposed a moratorium on the use of high-volume hydraulic fracturing. In addition to state laws, some local municipalities have adopted or are considering adopting land use restrictions, such as city ordinances, that may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular.
Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations. Seismic Activity. Earthquakes in some of our operating areas and elsewhere have prompted concerns about seismic activity and possible relationships with the energy industry.
Moreover, violations of pipeline safety regulations by our midstream service providers could result in the imposition of significant penalties which may impact the cost or availability of pipeline capacity necessary for our operations. 31 Table of Contents Index to Financial Statements Seismic Activity.
We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase.
Competition in our industry for qualified employees is intense. If we are unsuccessful in attracting and retaining skilled employees and managerial talent, our ability to compete effectively may be diminished. We also compete for the equipment required to explore, develop and operate properties. Typically, during times of rising commodity prices, drilling and operating costs will also increase.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves. We utilize multi-well pad drilling where practical. For example, in the Utica/Marcellus we drill multiple wells from a single pad.
Multi-well pad drilling may result in volatility in our operating results and delay the conversion of our PUD reserves. We utilize multi-well pad drilling where practical. Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location.
Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans. 33 Table of Contents Index to Financial Statements Legislation or regulatory initiatives intended to address seismic activity could restrict our drilling and production activities, as well as our ability to dispose of produced water gathered from such activities, which could have a material adverse effect on our business.
In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells. 33 Table of Contents Index to Financial Statements In our Utica/Marcellus and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active.
In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements regarding the permitting of produced water disposal wells or otherwise to assess the relationship between seismicity and the use of such wells.
Wells drilled on a pad are not turned to sales until all wells on the pad are drilled and cased and the drilling rig is moved from the location. In addition, existing wells that offset newly drilled wells may be temporarily shut in during the drilling and completion process.
In addition, existing wells that offset newly drilled wells may be temporarily shut in during the drilling and completion process.
In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation. 31 Table of Contents Index to Financial Statements Hydraulic Fracturing.
In addition, we could be subject to third-party lawsuits seeking damages or other remedies as a result of alleged induced seismic activity in our areas of operation. Hydraulic Fracturing. Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations.
The emissions fee and funding provisions of the IRA 2022 could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position. On January 26, 2024, the Biden Administration paused approvals for pending and future applications to export liquified natural gas (LNG) on non-FTA countries.
The emissions fee and funding provisions of the IRA 2022 could increase our operating costs and accelerate the transition away from fossil fuels, which could in turn adversely affect our business, results of operations and financial position. Under the Trump Administration, however, there has been a shift away from the previous administration's GHG program.
The impact on these federal actions remain unclear. States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities. Legislative and state initiatives to date have generally focused on the development of cap and trade or carbon tax programs.
However, state and local GHG initiatives may continue despite shifts in the federal approach to climate change. 32 Table of Contents Index to Financial Statements States in which we operate have imposed venting and flaring limitations designed to reduce methane emissions from oil and gas exploration and production activities.
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Recent PHMSA rules have also extended certain requirements for integrity assessments and leak detections beyond high consequence areas.
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A downgrade in our credit rating could significantly increase our collateral requirements for commercial contracts and derivatives and restrict or limit our access to trade credit or capital.
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Several states have adopted or are considering adopting regulations that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing operations. Three states (New York, Maryland and Vermont) have banned the use of high-volume hydraulic fracturing.
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Competitors that develop or adopt new technologies more quickly may gain a significant advantage, which could require us to incur substantial costs to remain competitive. Some industry participants have greater financial, technical, and personnel resources, enabling them to implement innovations sooner and more effectively than we can.
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On January 20, 2025, President Trump issued an executive order reversing the pause implemented by the Biden Administration, resuming the processing of export permit applications for new LNG projects.
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However, the methane emissions charge rule was repealed in February 2025 and the imposition of the charge under the IRA 2022 was postponed until 2034 under the One Big Beautiful Bill Act of July 2025. In December 2025, the USEPA issued a final rule extending several compliance deadlines and timeframes associated with the 2024 methane rules.
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Additionally, in January 2025 President Trump signed executive orders that, among other things, direct federal executive departments and agencies to initiate a regulatory freeze for certain rules that have not taken effect, pending review by the newly appointed agency head, and call upon the USEPA to submit a report on the continuing applicability of its endangerment finding for GHGs under the Clean Air Act and issue guidance on the “social cost of carbon” to consider whether such metric should be eliminated, and pause the disbursement of funds appropriated through the IRA 2022.
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In November 2025, BLM announced it will delay enforcement of two provisions of the Waste Prevention Rule that had been scheduled to take effect in December 2025 as it reviews the underlying rule and considers revisions. Litigation challenging the 2024 rule is currently held in abeyance.
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However, the designation of previously unidentified endangered or threatened species in areas where we intend to conduct construction activity or the imposition of seasonal restrictions on our construction or operational activities could materially limit or delay our plans.
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There have also been certain governmental reviews that focus on deep shale and other formation completion and production practices, including hydraulic fracturing. Governments may continue to study hydraulic fracturing.
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In recent years, increasing attention has been given to corporate activities related to ESG matters in public discourse and the investment community.
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For example, in February 2025, the U.S. House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge rule, which President Trump signed into law.
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A number of advocacy groups, both domestically and internationally, have campaigned for governmental and private action to promote change at public companies related to ESG matters, including through the investment and voting practices of investment advisers, public pension funds, activist investors, universities and other members of the investing community.
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In September 2025, the USEPA announced a proposal to end the GHG Reporting Program for all sectors except petroleum and natural gas systems (excluding reporting for natural gas distribution, which would also be eliminated under the proposal) and deferring reporting for petroleum and natural gas systems until 2034.
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These activities include increasing attention and demands for action related to climate change, advocating for changes to companies’ boards of directors, and promoting the use of energy saving building materials. On January 20, 2025, however, President Trump signed an executive order to withdraw the United States from the Paris Agreement, marking a significant shift in U.S. federal climate policy.
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In December 2025, the USEPA issued a final rule extending several compliance deadlines and timeframes associated with its 2024 methane rules.
Removed
Pursuant to the terms of the Paris Agreement, the withdrawal will take effect on January 27, 2026. State and local GHG initiatives may continue despite the U.S. withdrawal from the Paris Agreement.
Added
On February 12, 2026, the USEPA announced the repeal of its 2009 “Endangerment Finding” under the Clean Air Act, which found that GHGs endanger the public health and welfare of current and future generations and emissions of GHGs from motor vehicles contribute to GHG pollution.
Removed
A potential global transition to a low carbon economy may result in reduced demand for our oil, natural gas and NGL, reduced profits, increased investigations and litigation, each of which could have negative impacts on our access to capital markets.
Added
The repeal calls into question EPA's authority to regulate GHGs, as well as EPA's prior scientific assessment of climate change risks. Litigation regarding the repeal is anticipated and it is unclear how the repeal will impact EPA's regulation of GHG emissions going forward.
Added
In addition, federal or state carbon taxes could directly increase our costs of operation and similarly incentivize consumers to shift away from fossil fuels.
Added
In our Utica/Marcellus and SCOOP operations, we make an effort to reuse/recycle all produced water from production and completion activities through our fracture stimulation operations when active.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeThis year we implemented tools that provide additional visibility into lateral movement, enhancements for multifactor authentication, and patching of servers. Cyber risks and incidents are categorized by severity, evaluated for materiality, responded to based on defined incident response playbooks and then remediated accordingly.
Biggest changeDuring 2025, our investment focused on continuous improvement in cyber detections for our operations technology environment, threat and vulnerability management and data loss prevention. Cyber risks and incidents are categorized by severity, evaluated for materiality, responded to based on defined incident response playbooks and then remediated accordingly.
Our partnerships with law enforcement, the Oil and Natural Gas Information Sharing Center and our third party partners continually mature our cyber program as threats evolve. Engaging Third Parties on Risk Management Recognizing the complexity and evolving nature of cybersecurity risk, we leverage strategic external partnerships to assess and mitigate cybersecurity threats to us.
Our partnerships with law enforcement, the Oil and Natural Gas Information Sharing Center and our third-party partners continually mature our cyber program as threats evolve. Engaging Third Parties on Risk Management Recognizing the complexity and evolving nature of cybersecurity risk, we leverage strategic external partnerships to assess and mitigate cybersecurity threats.
Managing Third Party Risk We also recognize the risks associated with the use of vendors, service providers and other third parties that provide information system services to us, process information on our behalf, or have access to our information systems, and we have processes in place to oversee and manage these risks.
Managing Third Party Risk We recognize the risks associated with the use of vendors, service providers and other third parties that provide information system services to us, process information on our behalf, or have access to our information systems, and we have processes in place to oversee and manage these risks.
For example, in addition to our security analysts, we partner with third parties that provide 24/7 security operations monitoring, enhancing our response time. We are also audited by third parties for compliance with information security standards and assess vulnerabilities annually, providing additional expertise that strengthens our security posture.
For example, in addition to our security analysts, we partner with third parties that provide 24/7 security operations monitoring, enhancing our response time. We are also audited by third parties for compliance with information security standards and to assess vulnerabilities, providing additional expertise that strengthens our security posture.
We maintain ongoing monitoring to ensure compliance with our cybersecurity standards. Risks from Cybersecurity Incidents As of December 31, 2024, and for the past five years, we have identified no security incidents or breaches that are material, or likely to be material, to our business strategy, results or financial condition.
We maintain ongoing monitoring to ensure compliance with our cybersecurity standards. Risks from Cybersecurity Incidents As of December 31, 2025, and for the past five years, we have identified no security incidents or breaches that are material, or likely to be material, to our business strategy, results or financial condition.
We utilize a defense-in-depth approach, layering security starting with cloud-based tools through our perimeter all the way to the client and server end points with End Point Detection and Response solutions. We continue to invest and align advances in technology to strengthen our security posture.
We utilize a defense-in-depth approach, layering security starting with cloud-based tools through our perimeter all the way to the client and server endpoints with End Point Detection and Response solutions. We continue to invest and align advances in technology to strengthen our security posture.
We perform organized tabletop exercises to test these practices and identify areas where opportunities for improvement can occur. We acknowledge that—even with advanced security tools—we are only as strong as the people that use our technology. That is why we design phishing simulations and require multiple security trainings for every employee annually.
We perform organized tabletop exercises to test these practices and identify areas where opportunities for improvement exist. We acknowledge that—even with advanced security tools—we are only as strong as the people that use our technology. That is why we design phishing simulations and require multiple security training courses for every employee annually.
At the corporate level, cybersecurity is identified as a key risk within our Enterprise Risk Management (ERM) program. Our management of cyber risk is based on the National Institute of Standards and Technology’s (NIST) cybersecurity framework. While the NIST cybersecurity framework is our foundation, we combine that with the Center for Internet Security’s (CIS) control framework.
At the corporate level, cybersecurity is identified as a key risk within our Enterprise Risk Management (“ERM”) program. Our management of cyber risk is based on the National Institute of Standards and Technology’s (“NIST”) cybersecurity framework combined with the Center for Internet Security’s (“CIS”) control framework.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeLegal Proceedings is set forth in Note 18 of our consolidated financial statements.
Biggest change“Legal Proceedings” is set forth in Note 18 of our consolidated financial statements.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeDuring the years ended December 31, 2024, 2023 and 2022, the Company paid $4.2 million, $4.8 million and $5.4 million, respectively, of cash dividends to holders of our preferred stock.
Biggest changeDuring the years ended December 31, 2025, 2024 and 2023, the Company paid $1.7 million, $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock. During the third quarter of 2025, the Company redeemed its remaining outstanding preferred stock and no cash dividends were paid after September 5, 2025 (the “Redemption Date”).
The performance graph below illustrates changes over the period of May 19, 2021, through December 31, 2024, in cumulative total stockholder return on the common stock as measured against the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index.
The performance graph below illustrates changes over the period of May 19, 2021, through December 31, 2025, in cumulative total stockholder return on the common stock as measured against the cumulative total return of the S&P 500 Index and the S&P Oil & Gas Exploration and Production Index.
The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from May 19, 2021, to December 31, 2024. ITEM 6. [RESERVED]
The graph tracks the performance of a $100 investment in our common stock and in each index (with the reinvestment of all dividends for the index securities) from May 19, 2021, to December 31, 2025. ITEM 6. [RESERVED]
Issuer Purchases of Equity Securities In November 2021, the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1.0 billion and extended through December 31, 2025.
Issuer Purchases of Equity Securities In November 2021, the Company's Board of Directors approved the Repurchase Program to acquire up to $100 million of common stock, which has subsequently been increased up to $1.5 billion and extended through December 31, 2026.
Shareholders At the close of business on February 12, 2025, there were approximately 20,947 holders of record of our common stock. Dividends During the years ended December 31, 2024, 2023 and 2022, the Company has not paid dividends on our common stock.
Shareholders At the close of business on February 11, 2026, there were approximately 34,358 holders of record of our common stock. Dividends During the years ended December 31, 2025, 2024 and 2023, the Company has not paid dividends on our common stock.
The following table provides a summary of our common stock repurchase activity for the three months ended December 31, 2024: Period Total Number of Shares Purchased (1) Average Price Paid per Share Total number of shares purchased as part of publicly announced plans or programs Approximate maximum dollar value of shares that may yet be purchased under the plans or programs October 1 - October 31 115,448 $ 146.66 115,403 $ 129,071,000 November 1 - November 30 221,208 $ 169.14 221,208 $ 441,657,000 December 1 - December 31 154,569 $ 166.82 154,557 $ 415,874,000 Total 491,225 $ 163.13 491,168 _____________________ (1) We repurchased and canceled 45 and 12 shares of our common stock at a weighted average price of $143.69 and $174.48 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during October and December 2024, respectively.
The following table provides a summary of our common stock repurchase activity for the three months ended December 31, 2025: Period Total Number of Shares Purchased (1) Average Price Paid per Share Total number of shares purchased as part of publicly announced plans or programs Approximate maximum dollar value of shares that may yet be purchased under the plans or programs October 1 - October 31 179,419 $ 183.93 179,419 $ 681,611,000 November 1 - November 30 219,614 $ 209.46 219,614 $ 635,611,000 December 1 - December 31 265,630 $ 210.83 265,617 $ 579,611,000 Total 664,663 $ 203.11 664,650 _____________________ (1) We repurchased and canceled 13 shares of our common stock at a weighted average price of $201.85 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during December 2025.
As of December 31, 2024, the Company had repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share.
As of December 31, 2025, the Company had repurchased 7.4 million shares for $920.4 million at a weighted average price of $125.19 per share since the inception of the Repurchase Program.

Item 6. [Reserved]

Selected Financial Data — reserved (removed by SEC in 2021)

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Biggest changeITEM 6. RESERVED 40 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 40 RESULTS OF OPERATIONS 43 LIQUIDITY AND CAPITAL RESOURCES 48 CRITICAL ACCOUNTING POLICIES AND ESTIMATES 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 54 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 57
Biggest changeITEM 6. RESERVED 40 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 40 RESULTS OF OPERATIONS 43 LIQUIDITY AND CAPITAL RESOURCES 47 CRITICAL ACCOUNTING POLICIES AND ESTIMATES 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 54 ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 56

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeDepreciation, Depletion and Amortization (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Depreciation, depletion and amortization of oil and gas properties $ 324,078 $ 318,473 2 % Depreciation, depletion and amortization of other property and equipment 1,645 1,242 32 % Total depreciation, depletion and amortization $ 325,723 $ 319,715 2 % Total depreciation, depletion and amortization per Mcfe $ 0.84 $ 0.83 1 % Depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased 2% primarily the result of our drilling and development activities during 2023 and 2024.
Biggest changeTransportation, Gathering, Processing and Compression (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Transportation, gathering, processing and compression $ 358,938 $ 351,237 2 % Transportation, gathering, processing and compression per Mcfe $ 0.95 $ 0.91 4 % Transportation, gathering, processing and compression for the year ended December 31, 2025, compared to the year ended December 31, 2024, increased on a total and per unit basis primarily as a result of an increase in the proportion of natural gas liquids and oil and condensate production. 45 Table of Contents Index to Financial Statements Depreciation, Depletion and Amortization (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Depreciation, depletion and amortization of oil and gas properties $ 302,024 $ 324,078 (7) % Depreciation, depletion and amortization of other property and equipment 2,138 1,645 30 % Total depreciation, depletion and amortization $ 304,162 $ 325,723 (7) % Total depreciation, depletion and amortization per Mcfe $ 0.80 $ 0.84 (5) % The total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2025, compared to the year ended December 31, 2024, decreased primarily due to a lower depletion rate resulting from a decline in our amortization base from the full cost ceiling test impairments recorded during 2024, combined with a decrease in our production.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with “Item 8.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following discussion and analysis represents management’s perspective of our business, financial condition and overall performance. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future and should be read in conjunction with Item 8.
Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment.
Oil, Natural Gas and NGL Reserves. Estimates of oil and natural gas reserves and their values, future production rates, future development costs and commodity pricing differentials are the most significant of our estimates. The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment.
As discussed in Note 5 of our consolidated financial statements, holders of preferred stock are entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”).
As discussed in Note 5 of our consolidated financial statements, holders of preferred stock were entitled to receive cumulative quarterly dividends at a rate of 10% per annum of the Liquidation Preference with respect to cash dividends and 15% per annum of the Liquidation Preference with respect to dividends paid in kind as additional shares of preferred stock (“PIK Dividends”).
This quarterly review is referred to as a ceiling test. Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2024.
This quarterly review is referred to as a ceiling test. Two primary factors impacting this test are reserve estimates and the unweighted arithmetic average of the prices on the first day of each month within the 12-month period ended December 31, 2025.
Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2023 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2024 to the year ended December 31, 2023.
“Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2024 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2025 to the year ended December 31, 2024.
The significant change in the total gain for the year ended December 31, 2024 compared to the year ended December 31, 2023, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period.
The change in the total gain for the year ended December 31, 2025 compared to the year ended December 31, 2024, was primarily the result of changes in futures pricing for oil, natural gas, and NGLs during each period.
Discussions of our results from 2022 to 2023 that are not included in this Form 10-K can be found in “ Management's Discussion and Analysis of Financial Condition and Results of Operations ” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2023. 40 Table of Contents Index to Financial Statements Overview Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins.
Discussions of our results from 2023 to 2024 that are not included in this Form 10-K can be found in “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2024. 40 Table of Contents Index to Financial Statements Overview Gulfport is an independent natural gas-weighted exploration and production company with assets primarily located in the Appalachia and Anadarko basins.
Business and Industry Outlook The Company's primary focus going into 2025 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation.
Business and Industry Outlook The Company's primary focus going into 2026 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately enhance our expected free cash flow generation.
As of December 31, 2024, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2024, was $713.7 million compared to $668.0 million as of December 31, 2023.
As of December 31, 2025, our net working capital deficit includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2025, was $797.0 million compared to $713.7 million as of December 31, 2024.
The material changes that led to the decrease in net loss are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.
The material changes that led to the increase in net income are further discussed by category on the following pages. Some totals and changes throughout the below section may not sum or recalculate due to rounding.
If the prices of oil and natural gas decline further, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically.
If the prices of oil and natural gas continue to be volatile, our operations, financial condition and level of expenditures for the development of our oil and natural gas reserves may be materially and adversely affected. In addition, lower oil and natural gas prices may reduce the amount of oil and natural gas that we can produce economically.
To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 46% of our expected 2025 production, at an average floor price of $3.59 per Mcf.
To mitigate our exposure to commodity market volatility and to help provide a level of certainty around our financial strength, we have entered into a combination of natural gas swaps and collars, representing approximately 52% of our expected 2026 gas production, at an average floor price of $3.74 per Mcf.
Our principal properties are located in eastern Ohio targeting the Utica and Marcellus and in central Oklahoma targeting the SCOOP Woodford and Springer formations. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders.
Our principal operations target the Utica and Marcellus formations in eastern Ohio and the SCOOP Woodford and Springer formations in central Oklahoma. Our strategy is to develop our assets in a safe, environmentally responsible manner, while generating sustainable cash flow, improving margins and operating efficiencies and returning capital to shareholders.
The fair value losses of our hedging program totaled $253.1 million for the year ended December 31, 2024 compared to gains of $588.1 million for the year ended December 31, 2023. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements.
The net fair value gains of our hedging program totaled $42.6 million for the year ended December 31, 2025 compared to losses of $253.1 million for the year ended December 31, 2024. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 12 of our consolidated financial statements.
Net cash provided by operating activities was $650.0 million for the year ended December 31, 2024, compared to $723.2 million for the year ended December 31, 2023. The decrease was primarily the result of a decrease in our natural gas revenues. Additions to oil and natural gas properties.
Net cash provided by operating activities was $803.2 million for the year ended December 31, 2025, compared to $650.0 million for the year ended December 31, 2024. The increase was primarily the result of a increase in our natural gas revenues. Additions to oil and natural gas properties.
The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 7% increase in sales volumes, partially offset by a 5% decrease in realized oil prices.
The increase in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was due to a 55% increase in sales volumes, partially offset by a 15% decrease in realized oil prices.
We expect this capital program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025. Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty.
We expect this capital program to result in approximately 1.030 to 1.055 Bcfe per day of production in 2026. Commodity Price Risk. The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty.
The realized price change was primarily driven by the decrease in the average WTI crude index from $77.62 per barrel in the year ended December 31, 2023, to $75.72 per barrel during the year ended December 31, 2024.
The realized price change was primarily driven by the decrease in the average WTI crude index from $75.72 per barrel in the year ended December 31, 2024, to $64.81 per barrel during the year ended December 31, 2025.
Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities. In 2024, natural gas prices continued to be volatile as spot prices ranged from $1.21 to $13.20 per MMBtu.
Throughout the year, we plan to maintain capital discipline, prioritizing free cash flow generation and preserving our strong financial position, while returning capital to shareholders and increasing our resource depth through incremental leasehold opportunities. In 2025, natural gas prices continued to be volatile as spot prices ranged from $2.65 to $9.86 per MMBtu.
(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities. (5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties. See Notes 12 and 3 of our consolidated financial statements, respectively. Off-balance Sheet Arrangements.
(4) See Note 9 of our consolidated financial statements for a description of our operating lease liabilities. (5) This table does not include derivative liabilities or the estimated discounted cost for future abandonment of oil and natural gas properties.
Henry Hub averaged $2.19 per MMBtu in 2024 vs $2.53 per MMBtu in 2023. As we look into 2025, we expect continued volatility in natural gas prices.
Henry Hub averaged $3.52 per MMBtu in 2025 vs $2.19 per MMBtu in 2024. As we look into 2026, we expect continued volatility in natural gas prices.
The 7% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica liquids window.
The 55% increase in oil and condensate production was primarily due to commencement of sales on new wells targeting the Utica and Marcellus liquids windows.
The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was due to a 13% decrease in NGL sales volumes, partially offset by an 8% increase in realized prices.
The increase in NGL sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was due to a 19% increase in NGL sales volumes, partially offset by a 1% decrease in realized prices.
As of December 31, 2024, we had $1.5 million of cash and cash equivalents compared to $1.9 million as of December 31, 2023, and a net working capital deficit of $114.2 million as of December 31, 2024, compared to net working capital of $52.4 million as of December 31, 2023.
As of December 31, 2025, we had $1.8 million of cash and cash equivalents compared to $1.5 million as of December 31, 2024, and a net working capital deficit of $115.9 million as of December 31, 2025, compared to net working deficit of $114.2 million as of December 31, 2024.
The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $2.74 per Mcf in the year ended December 31, 2023, to $2.27 per Mcf during the year ended December 31, 2024.
The realized price change was primarily driven by the increase in the average Henry Hub gas index from $2.27 per Mcf in the year ended December 31, 2024, to $3.43 per Mcf during the year ended December 31, 2025.
Also, we currently expect to spend approximately $35 million to $40 million in 2025 for maintenance leasehold and land investment, which is focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2025, 2026 and 2027.
Also, we currently expect to spend approximately $35 million to $40 million in 2026 for maintenance land and seismic investments, primarily focused on near-term drilling programs and facilitating increases in our working interests and lateral footage in units we plan to drill in 2026, 2027 and 2028.
We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value. We estimate the fair value of all derivative instruments using industry-standard models that considered various assumptions including current market and contractual prices for the underlying instruments, implied volatility, time value, nonperformance risk, as well as other relevant economic measures.
During the year ended December 31, 2024, the Company incurred debt issuance and loan commitment fees of $14.9 million, as compared to $7.1 million during the year ended December 31, 2023. The increase was primarily related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility.
Debt issuance and loan commitment fees. During the year ended December 31, 2024, the Company incurred $14.9 million of debt issuance and loan commitment fees, related to the issuance of the 2029 Senior Notes and the Fourth Amendment to the Credit Facility.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt and preferred stock through privately negotiated transactions, open market repurchases, redemptions, tender offers or otherwise, but we are under no obligation to do so.
We may continue to use a combination of cash, borrowings and issuances of our common stock or other securities to retire our outstanding debt through privately negotiated transactions, open market repurchases, tender offers or otherwise, but we are under no obligation to do so. See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt.
We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts. All derivative instruments are recognized as assets or liabilities in the balance sheet, measured at fair value.
Derivative Instruments. We seek to reduce our exposure to unfavorable changes in natural gas, oil and NGL prices, which are subject to significant and often volatile fluctuation, by entering into over-the-counter fixed price swaps, basis swaps, costless collars and various types of option contracts.
Our hedging program generated cash receipts of $282.6 million for the year ended December 31, 2024, compared to cash receipts of $152.2 million for the year ended December 31, 2023.
Our hedging program generated cash receipts of $56.5 million for the year ended December 31, 2025, compared to cash receipts of $282.6 million for the year ended December 31, 2024.
During the year ended December 31, 2024, we spud 2 gross (1.8 net) operated wells and commenced sales from 3 gross (2.4 net) operated wells in the SCOOP for a total incurred cost of approximately $63.8 million. Additionally, the Company incurred $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
During the year ended December 31, 2025, we did not spud any operated wells and commenced sales from 2 gross (1.8 net) operated wells in the SCOOP for a total incurred cost of approximately $27.5 million. Additionally, the Company incurred $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions.
Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million.
Our drilling and completion capital expenditures for 2026 are currently estimated to be in the range of $365 million to $390 million.
For the year ended December 31, 2024, the Company's incurred capital expenditures totaled $430.1 million, of which $327.4 million related to drilling and completion activities, $57.9 million related to maintenance leasehold and land investment and $44.8 million related to discretionary acreage acquisitions.
For the year ended December 31, 2025, the Company's incurred capital expenditures totaled $526.1 million related to operated activities, of which $428.4 million related to drilling and completion activities, $34.8 million related to maintenance leasehold and land investment and $62.9 million related to discretionary acreage acquisitions.
During the year ended December 31, 2024, the Company paid $4.2 million of cash dividends to holders of our preferred stock compared to $4.8 million in the year ended December 31, 2023. Shares exchanged for tax withholdings.
During the year ended December 31, 2025, the Company paid $1.7 million of cash dividends to holders of our preferred stock compared to $4.2 million in the year ended December 31, 2024. No cash dividends were paid after the Redemption Date. Shares exchanged for tax withholdings.
Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors. Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations.
The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below. Our management has discussed each critical accounting estimate with the Audit Committee of our Board of Directors. Oil and Natural Gas Properties . We use the full cost method of accounting for oil and natural gas operations.
See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity. Repurchases of common stock. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for approximately $184.5 million under the Repurchase Program at a weighted average price of $153.35 per share.
See Note 4 of our consolidated financial statements for further discussion of the long-term debt activity. 51 Table of Contents Index to Financial Statements Repurchases of common stock. During the year ended December 31, 2025, the Company repurchased 1.8 million shares for approximately $336.3 million under the Repurchase Program at a weighted average price of $188.65 per share.
The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors.
The guarantees rank (i) senior in right of payment to any future subordinated indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (ii) pari passu in right of payment with all existing and future unsecured senior indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, (iii) effectively junior to any secured indebtedness of Gulfport Operating or the 2029 Senior Notes Guarantors, including indebtedness under the credit agreement, to the extent of the value of the collateral securing such indebtedness, and (iv) structurally subordinated in right of payment to all indebtedness and other liabilities of Gulfport Operating’s subsidiaries that are not 2029 Senior Notes Guarantors. 48 Table of Contents Index to Financial Statements SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10.
Cash capital expenditures for the year ended December 31, 2024 and 2023, were as follows (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 325,129 $ 413,258 Leasehold acquisitions 102,630 101,191 Other 26,339 22,911 Total oil and natural gas property expenditures $ 454,098 $ 537,360 Debt activity, net.
Cash capital expenditures for the year ended December 31, 2025 and 2024, were as follows (in thousands): Year Ended December 31, 2025 Year Ended December 31, 2024 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 404,239 $ 325,129 Leasehold acquisitions 95,610 102,630 Other 27,720 26,339 Total oil and natural gas property expenditures $ 527,569 $ 454,098 Debt activity, net.
There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
Additionally, we may access debt and equity markets and sell properties to enhance our liquidity. There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million. 42 Table of Contents Index to Financial Statements Results of Operations Comparison of the Year Ended December 31, 2024 and 2023 We reported net loss of $261.4 million for the year ended December 31, 2024, compared to a net income of $1.5 billion for the year ended December 31, 2023.
Our 2026 capital expenditure program is expected to be in a range of $400 million to $430 million, including $35 million to $40 million on maintenance land and seismic investments. 42 Table of Contents Index to Financial Statements Results of Operations Comparison of the Year Ended December 31, 2025 and 2024 We reported net income of $427.8 million for the year ended December 31, 2025, compared to a net loss of $261.4 million for the year ended December 31, 2024.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands) Year Ended December 31, 2024 Year Ended December 31, 2023 Natural gas (MMcf/day) Utica & Marcellus production volumes 810 766 SCOOP production volumes 157 194 Total production volumes 968 960 Total sales $ 714,160 $ 831,812 Average price without the impact of derivatives ($/Mcf) $ 2.02 $ 2.37 Impact from settled derivatives ($/Mcf) $ 0.80 $ 0.42 Average price, including settled derivatives ($/Mcf) $ 2.82 $ 2.79 Oil and condensate (MBbl/day) Utica & Marcellus production volumes 2 1 SCOOP production volumes 2 3 Total production volumes 4 4 Total sales $ 101,589 $ 99,854 Average price without the impact of derivatives ($/Bbl) $ 69.64 $ 73.27 Impact from settled derivatives ($/Bbl) $ 0.11 $ (2.53) Average price, including settled derivatives ($/Bbl) $ 69.75 $ 70.74 NGL (MBbl/day) Utica & Marcellus production volumes 3 2 SCOOP production volumes 8 10 Total production volumes 10 12 Total sales $ 112,855 $ 119,717 Average price without the impact of derivatives ($/Bbl) $ 29.56 $ 27.29 Impact from settled derivatives ($/Bbl) $ (0.56) $ 2.07 Average price, including settled derivatives ($/Bbl) $ 29.00 $ 29.36 Total (MMcfe/day) Utica & Marcellus production volumes 842 784 SCOOP production volumes 212 270 Total production volumes 1,054 1,054 Total sales $ 928,604 $ 1,051,383 Average price without the impact of derivatives ($/Mcfe) $ 2.41 $ 2.73 Impact from settled derivatives ($/Mcfe) $ 0.73 $ 0.40 Average price, including settled derivatives ($/Mcfe) $ 3.14 $ 3.13 43 Table of Contents Index to Financial Statements Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Natural gas $ 714,160 $ 831,812 (14) % Oil and condensate 101,589 99,854 2 % NGL 112,855 119,717 (6) % Total natural gas, oil and condensate and NGL sales $ 928,604 $ 1,051,383 (12) % The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2024, to the year ended December 31, 2023, was primarily due to a 15% decrease in realized natural gas prices, partially offset by a 1% increase in sales volumes.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands) Year Ended December 31, 2025 Year Ended December 31, 2024 Natural gas (MMcf/day) Utica & Marcellus production volumes 777 810 SCOOP production volumes 150 157 Total production volumes 927 968 Total sales $ 1,056,429 $ 714,160 Average price without the impact of derivatives ($/Mcf) $ 3.12 $ 2.02 Impact from settled derivatives ($/Mcf) $ 0.14 $ 0.80 Average price, including settled derivatives ($/Mcf) $ 3.26 $ 2.82 Oil and condensate (MBbl/day) Utica & Marcellus production volumes 5 2 SCOOP production volumes 1 2 Total production volumes 6 4 Total sales $ 133,644 $ 101,589 Average price without the impact of derivatives ($/Bbl) $ 59.12 $ 69.64 Impact from settled derivatives ($/Bbl) $ 4.04 $ 0.11 Average price, including settled derivatives ($/Bbl) $ 63.16 $ 69.75 NGL (MBbl/day) Utica & Marcellus production volumes 6 3 SCOOP production volumes 6 8 Total production volumes 12 10 Total sales $ 133,454 $ 112,855 Average price without the impact of derivatives ($/Bbl) $ 29.30 $ 29.56 Impact from settled derivatives ($/Bbl) $ (0.07) $ (0.56) Average price, including settled derivatives ($/Bbl) $ 29.23 $ 29.00 Total (MMcfe/day) Utica & Marcellus production volumes 841 842 SCOOP production volumes 197 212 Total production volumes 1,039 1,054 Total sales $ 1,323,527 $ 928,604 Average price without the impact of derivatives ($/Mcfe) $ 3.49 $ 2.41 Impact from settled derivatives ($/Mcfe) $ 0.15 $ 0.73 Average price, including settled derivatives ($/Mcfe) $ 3.64 $ 3.14 43 Table of Contents Index to Financial Statements Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Natural gas $ 1,056,429 $ 714,160 48 % Oil and condensate 133,644 101,589 32 % NGL 133,454 112,855 18 % Total natural gas, oil and condensate and NGL sales $ 1,323,527 $ 928,604 43 % The increase in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2025, to the year ended December 31, 2024, was primarily due to a 55% increase in realized natural gas prices, partially offset by a 4% decrease in sales volumes.
During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu. During 2023, WTI prices ranged from $66.61 to $93.67 per barrel and the Henry Hub spot market price of natural gas ranged from $1.74 to $3.78 per MMBtu.
During 2025, WTI prices ranged from $55.44 to $80.73 per barrel and the Henry Hub spot market price of natural gas ranged from $2.65 to $9.86 per MMBtu. During 2024, WTI prices ranged from $66.73 to $87.69 per barrel and the Henry Hub spot market price of natural gas ranged from $1.21 to $13.20 per MMBtu.
Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals. Derivative Instruments.
At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive. Variances between our estimated revenue and the actual amounts for product sales is recorded in the month that payment is received from the purchaser. Historically, our actual payments received have not significantly deviated from our accruals.
During 2024, the Company recognized ceiling test impairments of $373.2 million and did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023.
The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2025 and recognized ceiling test impairments of $373.2 million during 2024. See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting.
Subsequent to December 31, 2024 and as of February 20, 2025, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Average Price Natural Gas (MMBtu/d) ($/MMBtu) 2025 Swaps NYMEX Henry Hub 18,301 $3.85 2026 Basis Swaps Rex Zone 3 40,000 $(0.17) Oil (Bbl/d) ($/Bbl) 2025 Swaps NYMEX WTI 1,000 $70.87 50 Table of Contents Index to Financial Statements Contractual and Commercial Obligations.
Subsequent to December 31, 2025 and as of February 19, 2026, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Average Price Natural Gas (MMBtu/d) ($/MMBtu) 2026 Swaps NYMEX Henry Hub 36,603 $3.86 2027 Swaps NYMEX Henry Hub 40,000 $3.80 2027 Basis Swaps TETCO M2 50,000 $(0.80) 2027 Basis Swaps Rex Zone 3 30,000 $(0.22) 2027 Basis Swaps NGPL TXOK 30,000 $(0.34) Oil (Bbl/d) ($/Bbl) 2026 Costless Collars NYMEX WTI 1,125 $55.00 / $71.18 2027 Costless Collars NYMEX WTI 300 $55.00 / $68.00 Contractual and Commercial Obligations.
We currently have the option to pay either cash dividends or PIK Dividends on a quarterly basis. During the years ended December 31, 2024 and 2023, the Company paid $4.2 million and $4.8 million, respectively, of cash dividends to holders of our preferred stock. 49 Table of Contents Index to Financial Statements Supplemental Guarantor Financial Information .
We had the option to pay either cash dividends or PIK Dividends on a quarterly basis. On September 5, 2025, the Company redeemed all of its outstanding preferred stock. During the years ended December 31, 2025 and 2024, the Company paid $1.7 million and $4.2 million, respectively, of cash dividends to holders of our preferred stock.
SEC Regulation S-X Rule 13-01 requires the presentation of “Summarized Financial Information” to replace the “Condensed Consolidating Financial Information” required under Rule 3-10. Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements.
Rule 13-01 allows the omission of Summarized Financial Information if assets, liabilities and results of operations of the Guarantors are not materially different than the corresponding amounts presented in our consolidated financial statements. The Parent and Guarantor subsidiaries comprise our material operations.
Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized. Revenue Recognition. We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties.
Based upon the Company’s analysis, the Company currently believes that it is more likely than not that a portion of the Company's federal and state deferred tax assets will be utilized. 53 Table of Contents Index to Financial Statements Revenue Recognition.
Our capital expenditures have historically been related to the execution of our drilling and completion activities in addition to certain lease acquisition activities. Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices.
Our capital investment strategy is focused on prudently developing our existing properties to generate sustainable cash flow considering current and forecasted commodity prices.
During the year ended December 31, 2024, we spud 20 gross (19.7 net) operated wells and commenced sales from 16 gross (15.4 net) operated wells targeting the Utica formation for a total cost incurred of approximately $259.8 million.
During the year ended December 31, 2025, we spud 24 gross (23.9 net) operated wells and commenced sales from 30 gross (30.0 net) operated wells targeting the Utica and Marcellus formations for a total cost incurred of approximately $401.0 million.
For the year ended December 31, 2024, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, dividend payments on our preferred stock and discretionary acreage acquisitions.
For the year ended December 31, 2025, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations and access to the debt markets, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases, interest payments, dividend payments on our preferred stock and discretionary acreage acquisitions. 47 Table of Contents Index to Financial Statements We believe our annual free cash flow generation, borrowing capacity under the Credit Facility and cash on hand will provide sufficient liquidity to fund our operations, capital expenditures, interest expense and share repurchases during the next 12 months and the foreseeable future.
The Parent and Guarantor subsidiaries comprise our material operations. Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements. Derivatives and Hedging Activities .
Therefore, we concluded that the presentation of the Summarized Financial Information is not required as our Summarized Financial Information of the Guarantors is not materially different from our consolidated financial statements. Derivatives and Hedging Activities . Our results of operations and cash flows are impacted by changes in market prices for natural gas, oil and NGL.
Year Ended December 31, 2024 Year Ended December 31, 2023 Natural gas derivatives - fair value (losses) gains $ (251,019) $ 584,563 Natural gas derivatives - settlement gains 284,626 146,381 Total gains on natural gas derivatives 33,607 730,944 Oil and condensate derivatives - fair value gains 2,351 5,971 Oil and condensate derivatives - settlement gains (losses) 166 (3,272) Total gains on oil and condensate derivatives 2,517 2,699 NGL derivatives - fair value losses (4,442) (2,414) NGL derivatives - settlement (losses) gains (2,155) 9,090 Total (losses) gains on NGL derivatives (6,597) 6,676 Total gains on natural gas, oil and NGL derivatives $ 29,527 $ 740,319 We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period.
Year Ended December 31, 2025 Year Ended December 31, 2024 Natural gas derivatives - fair value gains (losses) $ 39,010 $ (251,019) Natural gas derivatives - settlement gains 47,705 284,626 Total gains on natural gas derivatives 86,715 33,607 Oil and condensate derivatives - fair value (losses) gains (3,468) 2,351 Oil and condensate derivatives - settlement gains 9,124 166 Total gains on oil and condensate derivatives 5,656 2,517 NGL derivatives - fair value gains (losses) 7,017 (4,442) NGL derivatives - settlement losses (332) (2,155) Total gains (losses) on NGL derivatives 6,685 (6,597) Total gains on natural gas, oil and NGL derivatives $ 99,056 $ 29,527 44 Table of Contents Index to Financial Statements We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period.
Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities. 51 Table of Contents Index to Financial Statements See Item 7A. “Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2024.
Reductions in commodity prices and/or our reserves could also negatively impact the borrowing base under our revolving credit facility, which could limit our liquidity and ability to fund development activities. See Item 7A.
Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery. At the end of each month, we estimate the amount of production delivered to purchasers that month and the price we will receive.
We derive almost all of our revenue from the sale of natural gas, crude oil and NGL produced from our oil and natural gas properties. Revenue is recorded in the month the product is delivered to the purchaser. We receive payment on substantially all of these sales from one to three months after delivery.
Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
“Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position. Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 Year Ended December 31, 2023 Net cash provided by operating activities $ 650,033 $ 723,181 Additions to oil and natural gas properties (454,098) (537,360) Debt activity, net 32,761 (27,000) Debt issuance and loan commitment fees (14,933) (7,068) Repurchases of common stock (184,477) (149,165) Dividends on preferred stock (4,230) (4,840) Shares exchanged for tax withholdings (23,614) (3,207) Other (1,898) 129 Net change in cash and cash equivalents $ (456) $ (5,330) Cash and cash equivalents at end of period $ 1,473 $ 1,929 Net cash provided by operating activities.
“Quantitative and Qualitative Disclosures about Market Risk” for further information regarding our open derivative instruments at December 31, 2025. 50 Table of Contents Index to Financial Statements Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2025 and 2024 (in thousands): Year Ended December 31, 2025 Year Ended December 31, 2024 Net cash provided by operating activities $ 803,193 $ 650,033 Additions to oil and natural gas properties (527,569) (454,098) Debt activity, net 83,298 32,761 Debt issuance and loan commitment fees (35) (14,933) Repurchases of common stock (304,961) (184,477) Redemption of preferred stock (32,423) — Net cash payments on performance vesting restricted stock units (12,297) — Dividends on preferred stock (1,666) (4,230) Shares exchanged for tax withholdings (5,579) (23,614) Other (1,621) (1,898) Net change in cash and cash equivalents $ 340 $ (456) Cash and cash equivalents at end of period $ 1,813 $ 1,473 Net cash provided by operating activities.
The impairment resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas. The 12-month average trailing price for natural gas in the third quarter of 2024 was $2.21 per MMBtu.
As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter and $342.7 million in the fourth quarter of 2024. The impairments resulted from declines in the full cost ceiling, which primarily resulted from the significant decrease in the 12-month average trailing price for natural gas.
The Company also capitalized $4.8 million and $4.1 million in interest expense for the years ended December 31, 2024 and 2023, respectively. 47 Table of Contents Index to Financial Statements Loss on Debt Extinguishment In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering.
See Note 4 of our consolidated financial statements for further details regarding our Credit Facility, issuance of the 2029 Senior Notes and retirement of the 2026 Senior Notes. Loss on Debt Extinguishment In September 2024, Gulfport Operating purchased and retired $524.3 million of the 2026 Senior Notes in a tender offer using net proceeds from the 2029 Senior Notes offering.
Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A . “Quantitative and Qualitative Disclosures About Market Risk” for further discussion on the impact of commodity price risk on our financial position.
To mitigate a portion of the exposure to adverse market changes, we have entered into various derivative instruments. Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the total revenue we will receive. See Item 7A.
See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected. See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes.
The following table sets forth our contractual and commercial obligations at December 31, 2024 (in thousands): Payment due by period Contractual Obligations Total 2025 2026-2027 2028-2029 2030 and Thereafter Long-term debt (1) : Principal $ 713,702 $ — $ 25,702 $ 688,000 $ — Interest 220,923 44,481 88,692 87,750 — Firm transportation and gathering contracts (2) 1,147,946 140,434 270,729 273,366 463,417 Other operational commitments (3) 13,791 13,791 — — — Operating lease liabilities (4) 6,228 5,657 571 — — Total contractual cash obligations (5) $ 2,102,590 $ 204,363 $ 385,694 $ 1,049,116 $ 463,417 _____________________ (1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations.
The following table sets forth our contractual and commercial obligations at December 31, 2025 (in thousands): Payment due by period Contractual Obligations Total 2026 2027-2028 2029-2030 2031 and Thereafter Long-term debt (1) : Principal $ 797,000 $ — $ 147,000 $ 650,000 $ — Interest 200,084 53,048 103,161 43,875 — Firm transportation and gathering contracts (2) 1,037,663 138,975 269,992 253,586 375,110 Other operational commitments (3) 16,409 16,409 — — — Operating lease liabilities (4) 571 561 10 — — Total contractual cash obligations (5) $ 2,051,727 $ 208,993 $ 520,163 $ 947,461 $ 375,110 _____________________ (1) The maturities of our debt obligations and associated interest reflect their original expiration dates and do not reflect any acceleration due to any events of default pertaining to these obligations.
Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions. The accounting estimates and assumptions we consider to be most significant to our financial statements are discussed below.
The decrease was primarily due to lower aggregate fair value of vested awards as discussed in Note 7 of our consolidated financial statements. 52 Table of Contents Index to Financial Statements Critical Accounting Policies and Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States require us to make estimates and assumptions.
The realized price change was primarily driven by the increase in the average Mont Belvieu NGL index from $30.07 per barrel in the year ended December 31, 2023, to $32.73 per barrel during the year ended December 31, 2024. 44 Table of Contents Index to Financial Statements Natural Gas, Oil and NGL Derivatives (in thousands) The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2024 and 2023, represented approximately 80% and 95%, respectively, of our total sales volumes for the applicable year.
Natural Gas, Oil and NGL Derivatives (in thousands) The total natural gas, oil and NGL volumes hedged for the year ended December 31, 2025 and 2024, represented approximately 73% and 80%, respectively, of our total sales volumes for the applicable year.
We strive to maintain sufficient liquidity to ensure financial flexibility, withstand commodity price volatility, fund our development projects, operations and capital expenditures and return capital to shareholders. We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows.
We utilize derivative contracts to reduce the financial impact of commodity price volatility and provide a level of certainty to the Company’s cash flows. We generally fund our operations, planned capital expenditures and any share repurchases with cash flow from our operating activities, cash on hand, and borrowings under our Credit Facility.
During the year ended December 31, 2024, the Company had $956.0 million and $1.0 billion in borrowings and repayments, respectively, on its Credit Facility. In September 2024, the Company purchased $524.3 million of the 2026 Senior Notes in a tender offer.
During the year ended December 31, 2025, the Company had $1.4 billion and $1.2 billion in borrowings and repayments, respectively, on its Credit Facility. In May 2025, the Company redeemed the remaining $25.7 million principal amount of its 2026 Senior Notes at par. As of February 19, 2026, the Company had $219.0 million in borrowings outstanding on its Credit Facility.
The 1% increase in natural gas production was primarily due to our 2023 and 2024 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.
The 4% decrease in natural gas production was primarily due to natural declines partially offset by our 2024 and 2025 development programs and the impact of unplanned, third-party midstream outages and constraints.
Stock Repurchase Program On November 4, 2024, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $650.0 million to $1.0 billion and extended the authorization through December 31, 2025. During the year ended December 31, 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share.
Recent Developments Share Repurchase Program and Redemption of Preferred Stock On August 4, 2025, the Company's Board of Directors approved an increase to the authorized Repurchase Program from $1.0 billion to $1.5 billion (including the redemption of preferred stock noted below) and extended the authorization through December 31, 2026.
During the year ended December 31, 2024, the Company paid $23.6 million of shares exchanged for tax withholdings compared to $3.2 million in the year ended December 31, 2023. The increase in shares traded for taxes was primarily due to the vesting of certain PSU awards as discussed in Note 7 of our consolidated financial statements. Other.
During the year ended December 31, 2025, the Company paid $5.6 million of shares exchanged for tax withholdings compared to $23.6 million in the year ended December 31, 2024.
As of February 20, 2025, we had $3.1 million of cash and cash equivalents, $10.0 million borrowings under our Credit Facility, $63.9 million of letters of credit outstanding, $25.7 million of outstanding 2026 Senior Notes and $650.0 million of outstanding 2029 Senior Notes. Debt. In May 2021, we issued our 2026 Senior Notes.
See Note 4 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our senior notes. As of February 19, 2026, we had $2.1 million of cash and cash equivalents, $219.0 million borrowings under our Credit Facility, $48.7 million of letters of credit outstanding and $650.0 million of outstanding 2029 Senior Notes.
There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources. See Note 17 of our consolidated financial statements for further discussion of the various financial guarantees we have issued. Capital Expenditures.
Additionally, the Company entered into various contractual commitments to purchase material and services to be used in future drilling and completion activities. There are no other transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of our capital resources.
For the same period in 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of February 20, 2025, we repurchased 5.6 million shares for approximately $593.2 million under the Repurchase Program at a weighted average price of $105.57 per share. Dividends on preferred stock.
For the same period in 2024, the Company repurchased 1.2 million shares for $184.5 million at a weighted average price of $153.35 per share. Redemption of preferred stock. On August 5, 2025, Gulfport issued a notice of redemption for its preferred stock for cash.
The 12-month average trailing price for natural gas in the fourth quarter of 2024 was $2.13 per MMBtu. 46 Table of Contents Index to Financial Statements Lower natural gas, oil and NGL prices can reduce the value of our assets.
The 12-month average trailing price for natural gas in the third quarter and fourth quarter of 2024 was $2.21 per MMBtu and $2.13 MMBtu, respectively. We did not incur an impairment of oil and natural gas properties during any quarter in 2025.
As of December 31, 2024, the Company repurchased 5.6 million shares for $584.1 million at a weighted average price of $104.88 per share since the inception of the Repurchase Program. 41 Table of Contents Index to Financial Statements 2024 Operational and Financial Highlights During 2024, we had the following notable achievements: • Reported total net production of 1,054 MMcfe per day. • Generated $650.0 million of operating cash flows. • Turned to sales 19 gross operated (17.8 net) wells. • Expanded common share repurchase program to $1.0 billion and returned $184.5 million to shareholders through the repurchase of 1.2 million shares at a weighted average price of $153.35 per share. • Extended the maturity of substantially all long-term senior notes from 2026 to 2029. • Extended the maturity of the Credit Facility to 2028 and increased the available commitments under the Credit Facility by $100 million. • Exited the year with total liquidity of $899.7 million. • Achieved MIQ certification for all Appalachian assets for the second consecutive year. • Reported year-end estimated net proved reserves of 4.0 Tcfe.
Key provisions of the OBBBA that are relevant to the Company include modifications to the limitations on the deductibility of interest expense under Section 163(j) of the Internal Revenue Code and adjustments to bonus depreciation rules. 41 Table of Contents Index to Financial Statements 2025 Operational and Financial Highlights During 2025, we had the following notable achievements: • Reported total net production of 1,039 MMcfe per day. • Generated $803.2 million of operating cash flows. • Turned to sales 32 gross operated (31.8 net) wells. • Redeemed outstanding preferred stock, simplifying our capital structure and eliminating future dividend obligations on the preferred stock. • Expanded common share repurchase program to $1.5 billion and returned $336.3 million to shareholders through the repurchase of 1.8 million shares (including the underlying shares of common stock into which the preferred stock was convertible) at a weighted average price of $188.65 per share. • Maintained a strong balance sheet and low financial leverage, exiting the year with total liquidity of $806.1 million. • Achieved MIQ certification for all Appalachia assets for the third consecutive year. • Reported year-end estimated net proved reserves of 4.3 Tcfe.
General and Administrative Expenses (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change General and administrative expenses, gross $ 82,478 $ 75,180 10 % Reimbursed from third parties (14,582) (13,770) 6 % Capitalized general and administrative expenses (25,338) (22,810) 11 % General and administrative expenses, net $ 42,558 $ 38,600 10 % General and administrative expenses, net per Mcfe $ 0.11 $ 0.10 10 % The increase in total and per unit general and administrative expenses for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily driven by increases in employee compensation and headcount.
General and Administrative Expenses (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change General and administrative expenses, gross $ 84,004 $ 82,478 2 % Reimbursed from third parties (16,269) (14,582) 12 % Capitalized general and administrative expenses (25,247) (25,338) — % General and administrative expenses, net $ 42,488 $ 42,558 — % General and administrative expenses, net per Mcfe $ 0.11 $ 0.11 — % The increase in total and per unit general and administrative expenses for the year ended December 31, 2025, compared to the year ended December 31, 2024, was primarily driven by increases in employee compensation and legal expense related to the matters disclosed in Note 18 of our consolidated financial statements. 46 Table of Contents Index to Financial Statements Interest Expense (in thousands, except per unit) Year Ended December 31, 2025 Year Ended December 31, 2024 % Change Interest on 2026 Senior Notes $ 777 $ 31,417 (98) % Interest on 2029 Senior Notes 43,875 13,163 233 % Interest on Credit Facility 9,390 14,143 (34) % Amortization of loan costs 5,258 4,208 25 % Capitalized interest (6,154) (4,771) 29 % Other 1,131 1,822 (38) % Total interest expense $ 54,277 $ 59,982 (10) % Interest expense per Mcfe $ 0.14 $ 0.16 (13) % Total interest expense for the year ended December 31, 2025, decreased 10% compared to the year ended December 31, 2024.
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2024, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $44.9 million in surety bonds issued.
As of December 31, 2025, our material off-balance sheet arrangements and transactions include $48.7 million in letters of credit outstanding against our Credit Facility and $45.3 million in surety bonds issued. Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements.
Income Taxes (in thousands) For the year ended December 31, 2024, we had an effective tax rate of 18% and an income tax benefit of $56.1 million. For the year ended December 31, 2023, the Company's effective tax rate was (56)% and an income tax benefit of $525.2 million.
The provisions did not have a significant effect on the Company’s tax positions for the current period. For the year ended December 31, 2025, our effective tax rate was 21.26% and an income tax expense of $115.5 million. For the year ended December 31, 2024, our effective tax rate was 17.66% and an income tax benefit of $56.1 million.
Impairment of Oil and Natural Gas Properties At September 30, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling. As a result, we recorded a non-cash ceiling test impairment of $30.5 million in the third quarter of 2024.
Our production decreased primarily due to natural declines and the impact of unplanned, third-party midstream outages and constraints, partially offset by our 2024 and 2025 development programs. Impairment of Oil and Natural Gas Properties At September 30, 2024 and December 31, 2024, the net book value of our oil and gas properties exceeded the calculated ceiling.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeWe believe our derivative instruments continue to be highly effective in achieving our risk management objectives. 54 Table of Contents Index to Financial Statements Our general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable rates of return on our invested capital.
Biggest changeOur general strategy for protecting short-term cash flow and attempting to mitigate exposure to adverse natural gas, oil and NGL price changes is to hedge into strengthening natural gas, oil and NGL futures markets when prices reach levels that management believes provide reasonable risk-adjusted rates of return and protect the financial position of the Company.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we will mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position.
We review our derivative positions continuously and if future market conditions change and prices are at levels we believe could jeopardize the effectiveness of a position, we mitigate this risk by either negotiating a cash settlement with our counterparty, restructuring the position or entering a new trade that effectively reverses the current position.
Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives.
These estimates are compared to counterparty valuations for reasonableness. Derivative transactions are also subject to the risk that counterparties will be unable to meet their obligations. This non-performance risk is considered in the valuation of our derivative instruments, but to date has not had a material impact on the values of our derivatives.
As of December 31, 2024, we did not have any interest rate swaps to hedge our interest risks. 56 Table of Contents Index to Financial Statements
As of December 31, 2025, we did not have any interest rate swaps to hedge our interest risks. 55 Table of Contents Index to Financial Statements
At December 31, 2024, we had $38.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 8.23% for the year ended December 31, 2024. A 1% increase in the average interest rate would increase interest expense by approximately $0.4 million based on outstanding borrowings under our Credit Facility at December 31, 2024.
At December 31, 2025, we had $147.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 6.53% for the year ended December 31, 2025. A 1% increase in the average interest rate would increase interest expense by approximately $1.5 million based on outstanding borrowings under our Credit Facility at December 31, 2025.
At December 31, 2024, we had a net liability derivative position of $12.9 million, compared to a net asset derivative position of $240.2 million as of December 31, 2023.
At December 31, 2025, we had a net asset derivative position of $29.7 million, compared to a net liability derivative position of $12.9 million as of December 31, 2024.
The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX. All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating-price, resulting in a net amount due to or from the counterparty.
All of our commodity derivative instruments are net settled based on the difference between the fixed price as stated in the contract and the floating price, resulting in a net amount due to or from the counterparty.
Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have increased our liability by approximately $82.3 million, while a 10% decrease in underlying commodity prices would have decreased our liability by approximately $81.8 million.
Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have decreased our asset by approximately $80.9 million, while a 10% decrease in underlying commodity prices would have increased our asset by approximately $80.9 million.
The factors we consider in closing or restructuring a position before the settlement date are identical to those we review when deciding to enter the original derivative position. We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models. These estimates are compared to counterparty valuations for reasonableness.
The factors we consider in closing or restructuring a position before the settlement date are consistent with those we review when deciding to enter the original derivative position. 54 Table of Contents Index to Financial Statements We have determined the fair value of our derivative instruments utilizing established index prices, volatility curves, discount factors and option pricing models.
Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive.
Our natural gas, oil and NGL derivative activities, when combined with our sales of natural gas, oil and NGL, allow us to predict with greater certainty the revenue we will receive. We believe our derivative instruments continue to be highly effective in achieving our risk management objectives.
As of December 31, 2024, our natural gas, oil, and NGL derivative instruments consisted of the following types of instruments: • Swaps : We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity.
As of December 31, 2025, our natural gas, oil and NGL derivative instruments consisted of the following types of instruments: • Swaps : We receive a fixed price and pay a floating market price to the counterparty for the hedged commodity. • Basis Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point.
If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty. • Call Options : We sell, and occasionally buy, call options in exchange for a premium.
If the applicable monthly price indices are outside of the ranges set by the floor and ceiling prices in the various collars, the Company will cash-settle the difference with the counterparty. Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase.
We do not enter into derivative contracts for volumes in excess of our share of forecasted production, and if production estimates were lowered for future periods and derivative instruments are already executed for some volume above the new production forecasts, the positions are typically reversed.
We do not enter into derivative contracts for volumes in excess of our share of forecasted production. The actual fixed prices on our derivative instruments is derived from the reference prices from third-party indices such as NYMEX.
Removed
In exchange for higher fixed prices on certain of our swap trades, we may sell call options. • Basis Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point.
Removed
At the time of settlement, if the market price exceeds the fixed price of the call option, we pay the counterparty the excess on sold call options, and we would receive the excess on bought call options.
Removed
If the market price settles below the fixed price of the call option, no payment is due from either party. 55 Table of Contents Index to Financial Statements Our hedge arrangements may expose us to risk of financial loss in certain circumstances, including instances where production is less than expected or commodity prices increase.

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