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What changed in GULFPORT ENERGY CORP's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of GULFPORT ENERGY CORP's 2023 and 2024 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 2024 report.

+351 added−357 removedSource: 10-K (2025-02-26) vs 10-K (2024-02-28)

Top changes in GULFPORT ENERGY CORP's 2024 10-K

351 paragraphs added · 357 removed · 282 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

96 edited+13 added−17 removed55 unchanged
Biggest change(2) The two gross wells that were drilled in 2023 were completed as producing wells as of December 31, 2023. 11 Table of Contents Inde x 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): Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Natural gas sales Natural gas production volumes (MMcf) 350,306 322,366 208,641 124,279 Natural gas production volumes (MMcf) per day 960 883 915 907 Total sales $ 831,812 $ 1,998,452 $ 906,096 $ 344,390 Average price without the impact of derivatives ($/Mcf) $ 2.37 $ 6.20 $ 4.34 $ 2.77 Impact from settled derivatives ($/Mcf) $ 0.42 $ (3.11) $ (1.44) $ (0.03) Average price, including settled derivatives ($/Mcf) $ 2.79 $ 3.09 $ 2.90 $ 2.74 Oil and condensate sales Oil and condensate production volumes (MBbl) 1,363 1,610 1,167 531 Oil and condensate production volumes (MBbl) per day 4 4 5 4 Total sales $ 99,854 $ 147,444 $ 81,347 $ 29,106 Average price without the impact of derivatives ($/Bbl) $ 73.27 $ 91.58 $ 69.71 $ 54.81 Impact from settled derivatives ($/Bbl) $ (2.53) $ (24.32) $ (8.33) $ — Average price, including settled derivatives ($/Bbl) $ 70.74 $ 67.26 $ 61.38 $ 54.81 NGL sales NGL production volumes (MBbl) 4,386 4,483 2,658 1,211 NGL production volumes (MBbl) per day 12 12 12 9 Total sales $ 119,717 $ 184,963 $ 105,141 $ 36,780 Average price without the impact of derivatives ($/Bbl) $ 27.29 $ 41.26 $ 39.56 $ 30.37 Impact from settled derivatives ($/Bbl) $ 2.07 $ (2.80) $ (4.88) $ — Average price, including settled derivatives ($/Bbl) $ 29.36 $ 38.46 $ 34.68 $ 30.37 Natural gas, oil and condensate and NGL sales Natural gas equivalents (MMcfe) 384,802 358,924 231,594 134,735 Natural gas equivalents (MMcfe) per day 1,054 983 1,016 983 Total sales $ 1,051,383 $ 2,330,859 $ 1,092,584 $ 410,276 Average price without the impact of derivatives ($/Mcfe) $ 2.73 $ 6.49 $ 4.72 $ 3.05 Impact from settled derivatives ($/Mcfe) $ 0.40 $ (2.94) $ (1.39) $ (0.02) Average price, including settled derivatives ($/Mcfe) $ 3.13 $ 3.55 $ 3.33 $ 3.03 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.18 $ 0.18 $ 0.14 $ 0.14 Average taxes other than income ($/Mcfe) $ 0.09 $ 0.17 $ 0.13 $ 0.09 Average transportation, gathering, processing and compression ($/Mcfe) $ 0.91 $ 1.00 $ 0.92 $ 1.20 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.17 $ 1.34 $ 1.19 $ 1.43 Totals may not sum or recalculate due to rounding. 12 Table of Contents Inde x 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, 2023: Successor Predecessor Year Ended December 31, 2023 Year Ended December 31, 2022 Period from May 18, 2021 through December 31, 2021 Period from January 1, 2021 through May 17, 2021 Utica & Marcellus Net Production Natural gas (MMcf) 279,428 246,123 166,906 106,968 Oil (MBbl) 255 244 220 183 NGL (MBbl) 856 885 562 361 Total (MMcfe) 286,095 252,895 171,598 110,235 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 2.34 $ 6.14 $ 4.33 $ 2.64 Oil ($/Bbl) $ 70.18 $ 90.60 $ 66.94 $ 52.43 NGL ($/Bbl) $ 33.63 $ 48.21 $ 47.16 $ 37.21 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.16 $ 0.17 $ 0.13 $ 0.13 Average taxes other than income ($/Mcfe) 0.05 0.06 0.07 0.06 Average transportation, gathering, processing and compression ($/Mcfe) 0.97 1.08 0.98 1.26 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.18 $ 1.31 $ 1.18 $ 1.45 SCOOP Net Production Natural gas (MMcf) 70,878 76,242 41,724 17,302 Oil (MBbl) 1,108 1,366 933 344 NGL (MBbl) 3,530 3,598 2,095 849 Total (MMcfe) 98,707 106,024 59,893 24,461 Average price without the impact of derivatives: Natural gas ($/Mcf) $ 2.53 $ 6.38 $ 4.40 $ 3.59 Oil ($/Bbl) $ 73.98 $ 91.71 $ 70.37 $ 56.05 NGL ($/Bbl) $ 25.76 $ 39.56 $ 37.51 $ 27.46 Production Costs: Average lease operating expenses ($/Mcfe) $ 0.25 $ 0.20 $ 0.17 $ 0.22 Average taxes other than income ($/Mcfe) 0.17 0.38 0.29 0.20 Average transportation, gathering, processing and compression ($/Mcfe) 0.73 0.78 0.74 0.90 Total lease operating expenses, midstream costs and taxes other than income ($/Mcfe) $ 1.15 $ 1.36 $ 1.20 $ 1.32 Our Investments Grizzly Oil Sands .
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 .
The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset, maximize cash flow, and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan.
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.
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 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.
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.
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.
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.
Oil, Natural Gas and NGL Reserves Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation.
Oil, Natural Gas and NGL Reserves and Estimation Reserve engineering is a subjective process of estimating volumes of economically recoverable oil, natural gas and NGL that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation.
In recent years, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. We consider the costs of environmental, safety and health protection and compliance to be necessary, manageable parts of our business.
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.
Craine has over 25 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry.
Craine has over 25 years of extensive senior-level experience handling a broad range of securities, corporate, regulatory, governance, compliance and litigation matters, with particular expertise in the energy industry. Mr.
We, through our wholly-owned subsidiary Grizzly Holdings Inc., own a 24.5% interest in Grizzly. As of December 31, 2023, 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, 2023.
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.
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, 2023. 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, 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.
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, 45, 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, 46, as Executive Vice President and Chief Financial Officer.
These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 18 of our consolidated financial statements for further discussion of our commitments.
These marketing activities often enhance the value of our production by aggregating volumes and allowing improved flexibility in relation to deal structure, size and counterparty exposure whether through intermediary markets or direct end markets. See Note 17 of our consolidated financial statements for further discussion of our commitments.
Craine, 51, 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, 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.
Over the course of 2023, 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 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.
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, 58, 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.
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.
Our aggregate payments for the retainer and clean-up services during each of 2023 and 2022 were immaterial.
Our aggregate payments for the retainer and clean-up services during each of 2024, 2023 and 2022 were immaterial.
See " Definitions " above for our definition of PV-10 (a non-GAAP financial measure) and " Oil, Natural Gas and NGL Reserves " 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.
We remain committed to providing fair and competitive compensation programs and adequate development and advancement opportunities to our employees. We believe these practices serve as retention tools, as our employees' continued engagement and commitment to the Company is critical to our success.
We remain committed to providing fair and competitive compensation programs and adequate development and advancement opportunities to our employees. We believe these practices serve as talent acquisition and retention tools, as our employees' continued engagement and commitment to the Company is critical to our success.
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".
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”.
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 444.9 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 406 Bcfe in estimated proved reserves.
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, 2023.
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.
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 995.7 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 547 Bcfe of proved reserves were primarily attributable to the continued development of our Utica/Marcellus and SCOOP acreage.
Totals may not sum due to rounding. 10 Table of Contents Inde x to Financial Statements Drilling Activity The following table sets forth information with respect to operated wells drilled during the periods indicated.
Totals may not sum due to rounding. 10 Table of Contents Index to Financial Statements Drilling Activity The following table sets forth information with respect to operated wells drilled during the periods indicated.
We cannot predict with any reasonable degree of certainty our future exposure concerning such matters 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 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.
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. 2024 Outlook Our 2024 capital expenditure program is expected to be in a range of $380 million to $420 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. 2025 Outlook Our 2025 capital expenditure program is expected to be in a range of $370 million to $395 million.
We focus on making substantive improvements to key areas that impact our employees. During 2023, 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, and 401(k) matches for eligible employees.
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.
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 $26 million as of December 31, 2023.
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.
Prior to joining Noble in 2007, he spent over 20 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr.
Prior to that role, he spent over 17 years developing his skills and expertise in unconventional resource development, reservoir engineering, subsurface development, business development/M&A, and leadership at Noble Energy, Santos Australia and Santos USA. Mr. Sluiter began his career as a wireline field services engineer for Schlumberger in Thailand. Mr.
We have approximately 73,000 net reservoir acres (comprised of approximately 41,000 in the Woodford formation and approximately 32,000 in the Springer formation) located primarily in Garvin, Grady and Stephens Counties.
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.
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, 2023, we had 4.2 Tcfe of proved reserves with a Standardized Measure of $2.4 billion and a PV-10 of $2.4 billion.
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.
Human Capital Management Employees As of December 31, 2023, we had 226 employees, an increase of approximately 1% from the 223 employees as of December 31, 2022. 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, 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.
The executive officers serve at the pleasure of the Company's Board of Directors. 19 Table of Contents Inde x to Financial Statements
The executive officers serve at the pleasure of the Company's Board of Directors. 19 Table of Contents Index to Financial Statements
PV-10 Sensitivities As noted above, our proved reserves at December 31, 2023, were calculated using prices based on the 12-month unweighted arithmetic average of the first-day-of-the-month price for 2023 of $78.21 per barrel and $2.64 per MMBtu.
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.
Extensions and discoveries. Our extensions of approximately 988.2 Bcfe were primarily attributed to the addition of 93 PUD drilling locations as a result of our current five-year development plan that is focused on generating sustainable cash flow. These additions included 79 PUD drilling locations in the Utica/Marcellus and 14 PUD drilling locations in the SCOOP. Conversion to proved developed reserves.
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.
Mr. 18 Table of Contents Inde x to Financial Statements Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law. Matthew Rucker, Senior Vice President of Operations Mr.
Craine received his Bachelor of Arts degree, summa cum laude, Phi Beta Kappa, from Wabash College, and his Juris Doctorate, cum laude, from the Southern Methodist University Dedman School of Law. 18 Table of Contents Index to Financial Statements Matthew Rucker, Executive Vice President and Chief Operating Officer Mr.
Year Ended December 31, 2023 2022 2021 Gross Net Gross Net Gross Net Development: Productive 24 21.9 25 21.7 29 26.6 Dry — — — — — — Total 24 21.9 25 21.7 29 26.6 Exploratory: Productive — — — — — — Dry — — — — — — Total — — — — — — The following table presents activity by operating area for the year ended December 31, 2023: Operated Non-Operated Field Drilled Turned to Sales Drilled Turned to Sales Gross Net Gross Net Gross Net Gross Net Utica & Marcellus (1) 22.0 20.2 22.0 20.2 10.0 0.3 7.0 0.1 SCOOP (2) 2.0 1.7 2.0 1.7 19.0 0.0 11.0 0.0 Total 24.0 21.9 24.0 21.9 29.0 0.3 18.0 0.1 _____________________ (1) Of the 22 gross wells drilled in 2023, 16 were completed as producing wells and six were in various stages of drilling and completion as of December 31, 2023.
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.
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 2023, we produced approximately 270 MMcfe per day net to our interests in this area and it accounts for approximately 26% 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 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.
Rucker served as the Executive Vice President, Chief Operating Officer for Montage Resources Corporation following Montage’s successful business combination transaction with Blue Ridge Mountain Resources in June 2020. Prior to Montage, Mr. Rucker served as Vice President, Resource Planning and Development of Blue Ridge from 2016 to 2020. Prior to joining Blue Ridge, Mr.
Rucker joined Javelin in July 2022 as the Vice President of Business Development. Prior to joining Javelin, Mr. Rucker served as the Executive Vice President, Chief Operating Officer for Montage Resources Corporation following Montage’s successful business combination transaction with Blue Ridge Mountain Resources in June 2020. Prior to Montage, Mr.
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.
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.
These downward revisions were offset by upward revisions of 192.0 Bcfe in estimated proved reserves from a combination of changes including working interest and net revenue interest, well development design and well forecasts. Costs incurred relating to the development of PUDs were approximately $362.9 million in 2023.
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.
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, 2023, December 31, 2022, Prior Successor Period, and Prior Predecessor Period were as follows: % of Sales Year Ended December 31, 2023 (Successor) Vitol Inc. 12 % Year Ended December 31, 2022 (Successor) ECO-Energy 20 % Clearwater 11 % Period from May 18, 2021 through December 31, 2021 (Successor) ECO-Energy 20 % Macquarie 10 % Period from January 1, 2021 through May 17, 2021 (Predecessor) ECO-Energy 14 % Macquarie 12 % Citadel 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, 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.
These were offset by downward revisions of 554.9 Bcfe which were primarily a result of development schedule changes with some PUD well design changes. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing these wells five years from initial booking.
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.
Holding production and development costs constant, if SEC pricing were $86.03 per barrel and $2.90 per MMBtu, or a 10% increase, this would have resulted in an increase of 53 Bcfe of our total proved reserves and a $0.6 billion increase in PV-10 value at December 31, 2023.
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 $0.54 billion increase in PV-10 value at December 31, 2024.
Our Marcellus development area is approximately 3,500 to 4,500 feet shallower than the Utica. SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations.
SCOOP - The SCOOP is a defined area that encompasses many of the top hydrocarbon producing counties in Oklahoma within the Anadarko Basin. The SCOOP play mainly targets the Devonian to Mississippian aged Woodford, Sycamore and Springer formations.
We expect this drilling program to result in approximately 1,045 to 1,080 MMcfe per day of production in 2024. 4 Table of Contents Inde x to Financial Statements Additionally, in 2024, we expect continuation of shareholder return actions through our Repurchase Program.
We expect this drilling program to result in approximately 1,040 to 1,065 MMcfe per day of production in 2025. 4 Table of Contents Index to Financial Statements Additionally, in 2025, we expect a continuation of shareholder return actions through our Repurchase Program.
However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase.
However, based on policy and regulatory trends and increasingly stringent laws, our capital expenditures and operating expenses related to compliance with the protection of the environment, safety and health have increased over the years and may continue to increase. We cannot predict with any reasonable degree of certainty our future exposure concerning such matters.
December 31, 2023 Proved Developed Proved Undeveloped Total Proved ($ in millions) Estimated future net revenue (1) $ 2,535 $ 2,235 $ 4,769 Present value of estimated future net revenue (PV-10) (1) $ 1,590 $ 819 $ 2,409 Standardized measure (1) $ 2,383 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, 2023, and assuming commodity prices as set forth below.
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.
Commodity prices experienced volatility throughout 2023 and the 12-month average price for natural gas decreased from $6.36 per MMBtu for 2022 to $2.64 per MMBtu for 2023, the 12-month average price for NGL decreased from $47.86 per barrel for 2022 to $31.42 per barrel for 2023, and the 12-month average price for crude oil decreased from $94.14 per barrel for 2022 to $78.21 per barrel for 2023.
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.
Holding production and development costs constant, if SEC pricing were $70.39 per barrel and $2.37 per MMBtu, or a 10% decrease, this would have resulted in a decrease of 313 Bcfe of our total proved reserves and a $0.6 billion decrease in PV-10 value at December 31, 2023.
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.
Reinhart, 55, as President and Chief Executive Officer, 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, 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.
We record PUD drilling 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.
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. The PUD locations identified in our development plan are determined based on an analysis of the information that we have available at that time.
During 2023, we repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share, leaving $250.4 million remaining on our Repurchase Program. Operating Areas Utica/Marcellus - The Utica covers hydrocarbon-bearing rock formations located in the Appalachian Basin of the United States and Canada.
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.
The prices used in our PV-10 measure were the average West Texas Intermediate Spot price of $78.21 per barrel and the average Henry Hub Spot price of $2.64 per MMBtu, before basis differential adjustments.
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.
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; • preparation of year-end reserve estimates by NSAI in coordination with our experienced reservoir engineers; • 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, as well as any changes to our previously adopted development plans; • annual review and approval by our senior management and our Board of Directors of a multi-year development plan; • annual review by our senior management of adjustments to our previously adopted development plan and considerations involved in making such adjustments; and • annual review by our Board of Directors of changes in our previously approved development plan made by senior management and technical staff during the year, including the substitution, removal or deferral of PUD locations.
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.
Some contracts require us to make payments for any shortfalls in delivering or transporting minimum volumes under these commitments. In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments.
In addition, we periodically enter into a variety of oil, natural gas and NGL purchase and sale contracts with third parties for various commercial purposes, including risk mitigation and satisfaction of our firm transportation delivery commitments.
The development schedule changes reflect our ongoing commitment to optimizing the long-term plan to best develop our asset, maximize cash flow, and overall economic returns. These locations excluded from our SEC reserves report remain in Gulfport's development plan. Additionally, downward revisions of 159.7 Bcfe were associated with commodity price changes.
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.
Additionally, we continued the WORK GREEN program, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives. An environmental training on the elements of WORK GREEN was created and delivered to all employees.
We continued to reinforce our WORK SAFE program and provided training to leaders on reinforcement strategies. Additionally, we continued the WORK GREEN program, which focuses on protecting the air, land and water where we operate and includes community-based volunteer events targeting environmental clean-up and habitat improvement initiatives.
Our 2023 development activities resulted in the conversion of approximately 419.7 Bcfe into proved developed producing reserves, attributable to 20 PUD locations in the Utica, 2 PUD locations in our Marcellus acreage and 3 PUD locations in the SCOOP. These 25 PUDs represent a conversion rate of 19% for 2023. Revision of prior reserve estimates.
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.
Approximately 79% and 21% of our PUD reserves at year-end 2023 were located in Utica/Marcellus and SCOOP, respectively. 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.
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. Our Senior Vice President of Reservoir Engineering is primarily responsible for overseeing the preparation of all of our reserve estimates.
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.
The PUD drilling 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.
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.
He serves on the Marietta College Industry Advisory Council and is a member of the Society of Petroleum Engineers. Michael Sluiter, Senior Vice President of Reservoir Engineering Mr. Sluiter, 51, 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, 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.
Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process.
Our internal staff of petroleum engineers and geoscience professionals work closely with NSAI to ensure the integrity, accuracy and timeliness of the data used to calculate our proved reserves. Our internal technical team members meet with NSAI periodically throughout the year to discuss the assumptions and methods used in the proved reserve estimation process.
Additional information regarding estimates of proved reserves, proved developed reserves and proved undeveloped reserves at December 31, 2023, 2022 and 2021, 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. 7 Table of Contents Inde x to Financial Statements Proved Undeveloped Reserves As of December 31, 2023, our PUDs totaled 1,746 Bcf of natural gas, 12 MMBbl of oil and 32 MMBbl of NGL, for a total of 2,011 Bcfe.
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.
These consisted of upward revisions of 24.9 Bcfe as a result of positive well performance and 293.9 Bcfe due to an increase in working interest and net revenue interest as a result of our successful leasing efforts through 2023.
These 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.
We experienced total downward revisions of 309.8 Bcfe in estimated proved undeveloped reserves. This included 501.8 Bcfe of downward revisions with changes in our development schedule. The schedule changes moved the development of 36 Utica/Marcellus PUD locations and 8 SCOOP PUD locations beyond the SEC requirement of developing PUDs five years from initial booking.
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.
We utilize training sessions with content developed by experts in the safety, legal, information security, and regulatory compliance fields, and we offer a blend of training sessions through both computer-based modules and live, instructor-led sessions. We believe our training efforts support a compliant safety-first mindset in everything we do.
We build our dynamic team of industry-leading professionals by engaging them in interesting and rewarding work and providing training and development opportunities. We utilize training sessions with content developed by experts in the safety, legal, information security, and regulatory compliance fields, and we offer a blend of training sessions through both computer-based modules and live, instructor-led sessions.
In the Utica, we intend to complete drilling on approximately 17 gross (16.4 net) operated horizontal wells and commence sales on approximately 16 gross (15.5 net) operated horizontal wells. In the SCOOP, we intend to complete drilling on approximately five gross (4.1 net) operated horizontal wells and commence sales on three gross (2.4 net) operated horizontal wells.
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.
The Marcellus covers hydrocarbon bearing rock formations that overlay the Utica. We have identified approximately 17,000 net reservoir acres of our existing leasehold for Marcellus development and have 15 PUD Marcellus locations within our Utica operating area. In 2023 we drilled, completed, and turned to sales two Marcellus wells.
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.
All PUD drilling locations included in our 2023 reserve report are scheduled to be drilled within five years of initial booking. As of December 31, 2023, 0.34% of our total proved reserves were classified as proved developed non-producing. Reserves Estimation Reserve estimates for the years ended December 31, 2023, 2022 and 2021, were prepared by Netherland, Sewell & Associates, Inc.
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.
Title to Oil and Natural Gas Properties It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations at the time we are preparing to develop the undeveloped leases and when acquiring producing properties.
Seasonal anomalies can minimize or exaggerate the impact on these operations, while extreme weather events can materially constrain our operations for short periods of time. 14 Table of Contents Index to Financial Statements Title to Oil and Natural Gas Properties It is customary in the oil and natural gas industry to make only a preliminary review of title to undeveloped oil and natural gas leases at the time they are acquired and to obtain more extensive title examinations at the time we are preparing to develop the undeveloped leases and when acquiring producing properties.
Marketing The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells. Generally, natural gas and NGL production is sold to purchasers under both spot and term transactions.
Failure to fund capital calls will lead to continued dilution of our equity ownership interest in Grizzly. 13 Table of Contents Index to Financial Statements Marketing The principal function of our marketing operations is to provide natural gas, oil and NGL marketing services, including securing and negotiating commodity transactions, gathering, hauling, processing and transportation services, contract administration and nomination services for production from Gulfport-marketed wells.
See the Risk Factors described in Item 1A. of this report for further discussion of 15 Table of Contents Inde x to Financial Statements governmental regulation and ongoing regulatory changes, including with respect to environmental matters. The SEC has also indicated plans to propose various other disclosure regulations, including regarding human capital and other ESG matters.
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.
The following table summarizes the changes in our estimated proved reserves during 2023 (in Bcfe): Proved Reserves, December 31, 2022 (Successor) 4,048 Sales of oil and natural gas reserves in place — Extensions and discoveries 996 Revisions of prior reserve estimates (445) Current production (385) Proved Reserves, December 31, 2023 (Successor) 4,214 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 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.
The following table summarizes the changes in our estimated proved undeveloped reserves during 2023 (in Bcfe): Proved Undeveloped Reserves, December 31, 2022 (Successor) 1,752 Sales of oil and natural gas reserves in place — Extensions and discoveries 988 Conversion to proved developed reserves (420) Revisions of prior reserve estimates (310) Proved Undeveloped Reserves, December 31, 2023 (Successor) 2,011 Total may not sum due to rounding.
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.
For the low price scenario 132 PUDs were PV-10 economic. 9 Table of Contents Inde x to Financial Statements Acreage The following table presents our total gross and net developed and undeveloped acres as of December 31, 2023: Developed Acreage Undeveloped Acreage Field Gross Net Gross Net Utica & Marcellus 148,747 121,387 75,547 72,058 SCOOP 49,909 35,844 8,537 6,035 Total 198,656 157,231 84,084 78,093 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 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.
We have prepared and have in place spill prevention control and countermeasure plans for each of our principal facilities in response to federal and state requirements. The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases.
The plans go through a technical review every five years and are updated as necessary. As required by applicable regulations, our facilities are built with secondary containment systems to capture potential releases. We also own additional spill kits with oil booms and absorbent pads that are readily available, if needed. In addition, we have emergency response companies on retainer.
A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. Our insurance coverage may not be sufficient to cover every claim made against us or may not be commercially available for purchase in the future.
A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows.
We added 79 PUD locations in the Utica/Marcellus which included 67 Utica locations for 789.2 Bcfe and 12 Marcellus locations for 88.6 Bcfe. In the SCOOP, we added 14 PUD locations for 110.4 Bcfe. Revisions of prior reserve estimates.
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 elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing. Failure to fund capital calls will lead to continued dilution of our equity ownership interest in Grizzly. 13 Table of Contents Inde x to Financial Statements Mammoth Energy.
We elected to cease funding capital calls in 2019, and we have no obligation to fund any future projects Grizzly may consider pursuing.
Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public, and the environment. We establish and carefully track key environmental and safety metrics that are a component of every employee’s incentive compensation opportunity annually.
As part of our focus on continuous improvement, we monitor and communicate key environmental and safety metrics both internally and externally. Trend analysis guides us to make operational changes and policy updates as necessary to protect our employees, the public and the environment.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

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Biggest changeThese factors include, among other things, our new capital structure as a result of the transactions contemplated by the Plan, our limited trading history subsequent to our emergence from bankruptcy, our limited trading volume, the lack of comparable historical financial information due to our adoption of fresh start accounting, actual or anticipated variations in our operating results and cash flow, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A of this Annual Report on Form 10-K. 34 Table of Contents Inde x to Financial Statements Future sales or the availability for sale of substantial amounts of our Common Stock, or the perception that these sales may occur, could adversely affect the trading price of our Common Stock and could impair our ability to raise capital through future sales of equity securities.
Biggest changeThese factors include, among other things, future sales of additional stock and changes in our capital structure, compliance with governmental regulations and taxation laws, actual or anticipated variations in our operating results and cash flow, allocation of free cash flow including any determination by our board of directors regarding repurchasing stock, the nature and content of our earnings releases, announcements or events that impact our products, customers, competitors or markets, business conditions in our markets and the general state of the securities markets and the market for energy-related stocks, as well as general economic and market conditions and other factors that may affect our future results, including those described in this Part I, Item 1A. of this Annual Report on Form 10-K.
The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management.
Pipeline Safety. The pipeline assets owned by our midstream service providers are subject to stringent and complex regulations related to pipeline safety and integrity management.
Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations.
Our technologies, systems, networks, and those of our vendors, suppliers and other business partners, have been and may become the target of cyberattacks or information security breaches that could result in the unauthorized access to our seismic data, reserves information, customer or employee data or other proprietary or commercially sensitive information could lead to data corruption, communication interruption, or other disruptions in our exploration or production operations or planned business transactions, any of which could have a material adverse impact on our results of operations.
State and federal regulatory agencies have recently focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity.
State and federal regulatory agencies have focused on a possible connection between hydraulic fracturing related activities, particularly the underground injection of wastewater into disposal wells, and the increased occurrence of seismic activity, and regulatory agencies at all levels are continuing to study the possible linkage between oil and gas activity and induced seismicity.
Concerns over global economic conditions, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices.
Concerns over global economic conditions, tariffs, energy costs, geopolitical issues, inflation, the availability and cost of credit and the European, Asian and the United States financial markets have contributed to economic volatility and diminished expectations for the global economy. Historically, concerns about global economic growth have had a significant impact on global financial markets and commodity prices.
The interests of these investors may not always coincide with the interests of the other holders of the Common Stock and other debt holders, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters.
The interests of these investors may not always coincide with the interests of the other holders of the common stock, and the concentration of control in these investors may limit other stockholders' ability to influence corporate matters.
Drilling and completion operations may be curtailed, delayed or cancelled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others.
Drilling and completion operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, title problems, equipment failures or accidents, shortages of midstream transportation, equipment or personnel, environmental issues, state or local bans or moratoriums on hydraulic fracturing and produced water disposal, and a decline in commodity prices, among others.
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 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; • 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 Inde x 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, 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.
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, 2023, our aggregate long-term contractual obligation under these agreements was approximately $1.4 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, 2024, our aggregate long-term contractual obligation under these agreements was approximately $1.1 billion.
Our oil and gas properties can become damaged, our operations may be curtailed, delayed or cancelled 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; • 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 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.
Even with natural gas, oil and NGL derivatives currently in place to mitigate price risks associated with a portion of our 2024 cash flows, we have substantial exposure to natural gas prices, and to a lesser extent, oil and NGL prices, in 2024 and beyond.
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.
If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or noncash write-down is required. A ceiling test impairment can result in a significant loss for a particular period.
If the net book value reduced by the related net deferred income tax liability exceeds the ceiling, an impairment or non-cash write-down is required. A ceiling test impairment can result in a significant loss for a particular period.
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.
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 have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed capital expenditures primarily with cash flow from operations, the issuance of equity and debt securities and borrowings under our revolving credit facility.
We have made and expect to make in the future substantial capital expenditures in our business and operations for the development, production, exploration and acquisition of oil and natural gas reserves. Historically, we have financed capital expenditures primarily with cash flow from operations and borrowings under our revolving credit facility.
These activities and the 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.
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.
Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations. 35 Table of Contents Inde x to Financial Statements ITEM 1B.
Alternatively, if a court were to find the choice of forum provision contained in our certificate of incorporation to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could have a material adverse effect on our business, financial condition and results of operations. ITEM 1B.
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.
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.
The emissions fee and funding provisions of the Inflation Reduction Act 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, President Biden 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. On January 26, 2024, the Biden Administration paused approvals for pending and future applications to export liquified natural gas (LNG) on non-FTA countries.
If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance 21 Table of Contents Inde x to Financial Statements with the financial covenants in our debt instruments in the future.
If commodity prices decline and we reduce our level of capital spending and production declines or we incur additional impairment expense or the value of our proved reserves declines, we may not be able to incur additional indebtedness, may need to repay outstanding indebtedness and may not be in compliance with the financial covenants in our debt instruments in the future.
Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations. 30 Table of Contents Inde x to Financial Statements Pipeline Safety.
Although we are unable to predict changes to existing laws and regulations, such changes could significantly impact our profitability, financial condition and liquidity. As is discussed below this is particularly true of changes related to pipeline safety, seismic activity, hydraulic fracturing, climate change and endangered species designations.
Refer to "Management's Discussion and Analysis of Financial Condition and Results of Operations" in Part II, Item 7 of this Annual Report on Form 10-K and Note 5 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.
Refer to “Management's Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K and Note 4 of our consolidated financial statements for more information regarding the financial covenants and our Credit Facility.
The Inflation Reduction Act of 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on greenhouse gas (GHG) emissions from certain facilities.
The IRA 2022, both imposes new climate related requirements on oil and gas operations and appropriates significant federal funding for renewable energy initiatives. Also, for the first time ever, the law imposes a fee on GHG emissions from certain facilities.
If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow. 28 Table of Contents Inde x to Financial Statements We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
If a substantial amount of our production is interrupted at the same time, it could materially adversely affect our cash flow. We are required to pay fees to some of our midstream service providers based on minimum volumes regardless of actual volume throughput.
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. 25 Table of Contents Inde x to Financial Statements 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 acreage must be drilled before lease expiration to hold the acreage by production.
The December 31, 2023 present value is based on a $2.64 per MMBtu of gas price and a $78.21 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, 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.
Of the remaining 14% of our Utica/Marcellus acreage not held by production, approximately 10% will be subject to expiration in 2024, 5% in 2025, 10% in 2026 and approximately 75% 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 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.
A large percentage of our Common Stock is held by a relatively small number of investors. In connection with our emergence from bankruptcy protection, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our Common Stock by such investors.
In connection with our emergence from bankruptcy protection in 2021, we entered into the Registration Rights Agreement pursuant to which we have agreed to file a registration statement with the SEC to facilitate potential future sales of our common stock by such investors.
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. 23 Table of Contents Inde x to Financial Statements As of December 31, 2023, approximately 48% 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, 2024, approximately 47% of our total estimated proved reserves were PUDs and may not be ultimately developed or produced.
An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our Credit Facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition. As of December 31, 2023, we did not hedge our interest rate risk.
An increase in our interest rate at the time we have variable interest rate borrowings outstanding under our Credit Facility will increase our costs, which may have a material adverse effect on our results of operations and financial condition.
The market price of our Common Stock could be subject to wide fluctuations in response to, and the level of trading that develops with our Common Stock may be affected by, numerous factors, many of which are beyond our control.
Risks Associated with an Investment in Us The market price of our securities is subject to volatility. The market price of our common stock could be subject to wide fluctuations in response to, and the level of trading that develops with our common stock may be affected by, numerous factors, many of which are beyond our control.
Our systems for protecting against cybersecurity risks may not be sufficient. As cyberattacks continue to evolve, including those leveraging artificial intelligence, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks.
As cyberattacks continue to evolve, including those leveraging artificial intelligence, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerabilities to cyberattacks.
Further, the Bureau for Land Management (BLM) issued a proposed Methane Waste Prevention Rule on November 30, 2022. 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 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.
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.
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”.
Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities. Such assessments are inexact and inherently uncertain.
We have a substantial inventory of undeveloped properties. Development and exploratory drilling and production activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Acquiring oil and natural gas properties requires us to assess reservoir and infrastructure characteristics, including recoverable reserves, development and operating costs and potential environmental and other liabilities.
For example, in December 2023, the United States Environmental Protection Agency (USEPA), announced 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 established the Methane Emissions Reduction Program, which imposes a charge on methane emissions from the same facilities.
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.
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. 29 Table of Contents Inde x to Financial Statements In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
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.
These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows.
These proposed changes in the U.S. federal and state tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flows. 34 Table of Contents Index to Financial Statements Our business is subject to complex and evolving laws and regulations regarding privacy and data protection.
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.
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.
As a result, these investors could have significant influence over all matters presented to our stockholders and debt holders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.
A large percentage of our equity is held by a relatively small number of investors. As a result, these investors could have significant influence over all matters presented to our stockholders for approval, including election and removal of our directors, change in control transactions and the outcome of all actions requiring majority stockholder approval.
At December 31, 2023, amounts borrowed under our Credit Facility bore interest at the weighted average rate of 8.15%. A 1% increase in the average interest rate would increase our interest expense by approximately $1.2 million based on outstanding borrowings under our Credit Facility at December 31, 2023.
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.
Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor. Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns. We have a substantial inventory of undeveloped properties.
Interest rates in effect from time to time and the risks associated with our business or the oil and gas industry in general will affect the appropriateness of the 10% discount factor. 24 Table of Contents Index to Financial Statements Our development and exploratory drilling efforts and our well operations may not be profitable or achieve our targeted returns.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S.
Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow. From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and gas industry. For example, legislative proposals have been introduced in the U.S.
Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including nonproductive costs and certain general and administrative costs associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline. We cannot necessarily observe structural and environmental problems, such as pipe corrosion, when an inspection is made.
Such assessments are inexact and inherently uncertain. In connection with the assessments, we perform a review of the subject properties, but such a review will not necessarily reveal all existing or potential problems. In the course of our due diligence, we may not inspect every well or pipeline.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited.
In addition, when we are not the majority owner or operator of a particular oil or natural gas project, if we are not willing or able to fund our capital expenditures relating to such projects when required by the majority owner or operator, our interests in these projects may be reduced or forfeited. 27 Table of Contents Index to Financial Statements Oil and natural gas production operations, especially those using hydraulic fracturing, are substantially dependent on the availability of water.
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, 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.
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.
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.
We cannot predict the effect that future sales of our Common Stock will have on the price at which the Common Stock trades. Sales of substantial amounts of our Common Stock, or the perception that such sales could occur, may adversely affect the trading price of our Common Stock.
We cannot predict the effect that future sales of our common stock will have on the price at which the common stock trades.
In addition, we may be unable to implement our development plan, complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations.
In addition, we may be unable to implement our development plan, complete acquisitions, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our production, revenues and results of operations. 22 Table of Contents Index to Financial Statements Under our method of accounting for oil and natural gas properties, declines in commodity prices may result in impairment of asset value.
Our largest fields by production are located in eastern Ohio and central Oklahoma. As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure.
As a result, we may be disproportionately exposed to the impact of delays or interruptions of production in these geographic regions caused by weather conditions such as snow, ice, fog, rain, hurricanes, tornados or other natural disasters or lack of field infrastructure. Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage.
New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect, use, share, and store personal data related to royalty owners. Any failure to comply with these laws and regulations could result in significant penalties and legal liability.
The regulatory environment surrounding data privacy and protection is constantly evolving and can be subject to significant change. New laws and regulations governing data privacy and the unauthorized disclosure of confidential information pose increasingly complex compliance challenges and potentially elevate our costs as we collect, use, share, and store personal data related to royalty owners.
These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closing claims for indemnification. Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing.
These transactions also have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets or businesses and potential post-closing claims for indemnification.
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. 33 Table of Contents Inde x to Financial Statements Future U.S. and state tax legislation may adversely affect our business, results of operations, financial condition and cash flow.
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.
With respect to our Utica/Marcellus acreage where we are focusing a portion of our exploration and development activity, operations may be delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider.
A significant disruption in the availability of these transportation facilities or our compression and other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. 28 Table of Contents Index to Financial Statements With respect to our Utica/Marcellus acreage where we are focusing a portion of our exploration and development activity, operations may be delayed due to challenges in obtaining rights-of-way and acquiring necessary state and federal permitting and the completion of facilities by our midstream service provider.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. 26 Table of Contents Inde x to Financial Statements While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority.
While we may maintain insurance against some, but not all, of the risks described above, our insurance may not be adequate to cover casualty losses or liabilities, and our insurance does not cover penalties or fines that may be assessed by a governmental authority.
Three states (New York, Maryland and Vermont) have banned 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.
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.
The impact on the pause and similar federal actions remain unclear. 31 Table of Contents Inde x 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.
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.
We acquire significant amounts of unproven properties that we believe will enhance our growth potential and increase our earnings over time. However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments.
However, we cannot assure you that all prospects will be economically viable or that we will not abandon our initial investments.
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.
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.
We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats.
Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities. We depend on digital technology to estimate quantities of oil, natural gas and NGL reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our customers, employees and third-party partners.
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. 32 Table of Contents Inde x 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.
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 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.
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.
If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition.
If we incur significant expense in acquiring or developing properties that do not produce as expected or at profitable levels, it could have a material adverse effect on our results of operations and financial condition. 25 Table of Contents Index to Financial Statements Part of our strategy involves using the latest available horizontal drilling and completion techniques; therefore, the results of our planned drilling in these plays are subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas.
An inability to secure sufficient amounts of water or to dispose of or recycle the water used in our operations could adversely impact our operations in certain areas. The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids.
Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program. Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us.
Natural gas, oil and NGL derivative transactions expose us to the risk that our counterparties, which are generally financial institutions, may be unable to satisfy their obligations to us. During periods of declining commodity prices, the value of our commodity derivative asset positions increase, which increases our counterparty exposure.
Once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase.
Once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if oil or gas prices increase. Future non-cash asset impairments could negatively affect our results of operations. A change of control could limit our use of net operating losses to reduce future taxable income.
Although 99% of our SCOOP acreage is held by existing production, the remaining acreage is subject to expiration. Of the remaining 1% of our SCOOP acreage not held by production, approximately 80% will be subject to expiration in 2024, less than 1% in 2025, 19% in 2026 and none thereafter.
Approximately 99% of our SCOOP acreage is held by existing production; the remaining acreage is subject to expiration.
Losses could occur for uninsured risks or in amounts in excess of any existing insurance coverage. We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available.
We may not be able to obtain and maintain adequate insurance at rates we consider reasonable and it is possible that certain types of coverage may not be available. The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows.
The loss of one or more of the purchasers of our production could adversely affect our business, results of operations, financial condition and cash flows. The largest purchaser of our oil and natural gas during the year ended December 31, 2023, accounted for approximately 12% of our total natural gas, oil and NGL revenues.
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.
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.
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.
Our debt and other financial commitments may limit our financial and operating flexibility. Our total principal debt was approximately $668.0 million at December 31, 2023. We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties.
We also had various commitments for leases, drilling contracts, derivative contracts, firm transportation, and purchase obligations for services, products and properties.
Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells. 24 Table of Contents Inde x to Financial Statements Drilling for oil and natural gas may involve unprofitable efforts, not only from dry wells but also from wells that are productive but do not produce sufficient commercial quantities to cover the drilling, operating and other costs.
Additionally, there can be no assurance that undeveloped properties acquired by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, or that we will recover all or any portion of our investment in such undeveloped properties or wells.
We may not be able to obtain contractual indemnities from the seller for liabilities created prior to our purchase of the property. We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations.
We may be required to assume the risk of the physical condition of the properties in addition to the risk that the properties may not perform in accordance with our expectations. We acquire unproven properties that we believe will enhance our growth potential and increase our earnings over time.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed. Our business has become increasingly dependent on digital technologies to conduct certain exploration, development and production activities.
These factors, combined with volatility in commodity prices, business and consumer confidence and unemployment rates, have in the past precipitated, and may in the future precipitate, an economic slowdown. 29 Table of Contents Index to Financial Statements Cyber-attacks targeting systems and infrastructure used by the oil and gas industry and related regulations may adversely impact our operations and, if we are unable to obtain and maintain adequate protection for our data, our business may be harmed.
Certain of our stockholders own a significant portion of our outstanding debt and equity securities and their interests may not always coincide with the interests of other holders of the Common Stock. A large percentage of our debt and equity are held by a relatively small number of investors.
Sales of substantial amounts of our common stock, or the perception that such sales could occur, may adversely affect the trading price of our common stock. 35 Table of Contents Index to Financial Statements Certain of our stockholders own a significant portion of our outstanding equity securities and their interests may not always coincide with the interests of other holders of the common stock.
The imposition of new environmental regulations could further restrict our ability to conduct operations such as hydraulic fracturing by restricting the disposal of things such as produced water and drilling fluids. 27 Table of Contents Inde x to Financial Statements All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions.
All of our producing properties are located in eastern Ohio and central Oklahoma, making us vulnerable to risks associated with operating in only these regions. Our largest fields by production are located in eastern Ohio and central Oklahoma.
Future non-cash asset impairments could negatively affect our results of operations. 22 Table of Contents Inde x to Financial Statements A change of control could limit our use of net operating losses to reduce future taxable income. As of December 31, 2023, we had a net operating loss, or NOL, carryforward of approximately $1.8 billion for federal income tax purposes.
As of December 31, 2024, we had a net operating loss, or NOL, carryforward of approximately $1.6 billion for federal income tax purposes.
Environmental, Legal and Regulatory Risks We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
Moreover, volatility in commodity prices may result in fewer potential bidders, unsuccessful sales efforts and a higher risk that buyers may seek to terminate a transaction prior to closing. 30 Table of Contents Index to Financial Statements Environmental, Legal and Regulatory Risks We are subject to extensive governmental regulation and ongoing regulatory changes, which could adversely impact our business.
We also may be unable to mitigate price volatility due to our exposure to long-dated call options and restrictions in our credit facility. We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable.
We may choose not to enter into derivatives if the pricing environment for certain time periods is not deemed to be favorable. Additionally, we may choose to liquidate existing derivative positions prior to the expiration of their contractual maturities to monetize gain positions for the purpose of funding our capital program.
Removed
For example, during 2022, West Texas intermediate light sweet crude oil, which we refer to as West Texas Intermediate or WTI, prices ranged from $71.05 to $123.64 per barrel and the Henry Hub spot market price of natural gas ranged from $3.46 to $9.85 per MMBtu.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeRisk Management Personnel Cybersecurity remains a top identified enterprise-wide risk for our business and is overseen by our Chief Information Officer who is responsible for identifying and mitigating information security risks. Our current CIO has 20 years of industry experience and over 10 years of experience with the development, training and controls of effective global enterprise cybersecurity programs.
Biggest changeCybersecurity Governance We involve multiple levels of oversight as a part of our approach to cybersecurity risk management. Risk Management Personnel Cybersecurity remains a top identified enterprise-wide risk for our business and is overseen by our Chief Information Officer who is responsible for identifying and mitigating information security risks.
These risks include, but are not limited to: financial risks, operational risks, safety concerns, employee and owner personal information and violation of data privacy or security laws. Managing Material Risks & Integrated Overall Risk Management We take an integrated approach to assessing and identifying cybersecurity risks and threats.
These risks include, but are not limited to: financial risks, operational risks, safety concerns, employee and owner personal information and violation of data privacy or security laws. 36 Table of Contents Index to Financial Statements Managing Material Risks & Integrated Overall Risk Management We take an integrated approach to assessing and identifying cybersecurity risks and threats.
Risks from Cybersecurity Incidents As of December 31, 2023, and for the past four 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. 36 Table of Contents Inde x to Financial Statements Cybersecurity Governance We involve multiple levels of oversight as a part of our approach to cybersecurity risk management.
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.
This year, for example, we implemented additional protections against phishing attacks by utilizing artificial intelligence to further strengthen our defense. Cyber risks and incidents are categorized by severity, evaluated for materiality, responded to based on defined incident response playbooks and then remediated accordingly.
This 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.
Additionally, we maintain an experienced information technology team at the employee level that supports our Chief Information Officer in implementing our cybersecurity program and internal reporting, security and mitigation functions.
Additionally, we maintain an experienced information technology team at the employee level that supports our Chief Information Officer in implementing our cybersecurity program and internal reporting, security and mitigation functions. 37 Table of Contents Index to Financial Statements Board of Director Oversight The Audit Committee receives a detailed cybersecurity update annually from the Chief Information Officer and receives a cybersecurity update quarterly through the ERM program as a key risk.
Removed
We maintain ongoing monitoring to ensure compliance with our cybersecurity standards.
Added
Our current CIO has 20 years of industry experience and over 10 years of experience with the development, training and controls of effective global enterprise cybersecurity programs.
Removed
Board of Director Oversight The Audit Committee receives a detailed cybersecurity update annually from the Chief Information Officer and receives a cybersecurity update quarterly through the ERM program as a key risk.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeLegal Proceedings is set forth in Note 19 of our consolidated financial statements.
Biggest changeLegal 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 changeThe following table provides a summary of our Common Stock repurchase activity for the three months ended December 31, 2023: 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 8,446 $ 115.40 8,398 $ 315,350,000 November 1 - November 30 94,240 $ 131.89 94,240 $ 302,921,000 December 1 - December 31 387,116 $ 135.83 387,037 $ 250,351,000 Total 489,802 $ 134.72 489,675 _____________________ (1) We repurchased and canceled 48 and 79 shares of our Common Stock at a weighted average price of $123.84 and $121.31 to satisfy tax withholding requirements incurred upon the vesting of restricted stock unit awards during October and December 2023, respectively.
Biggest changeThe 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 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, 2023. 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, 2024. ITEM 6. [RESERVED]
During the years ended December 31, 2023 and December 31, 2022, the Company paid $4.8 million and $5.4 million, respectively, of cash dividends to holders of our Preferred Stock.
During 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.
The performance graph below illustrates changes over the period of May 19, 2021 through December 31, 2023, in cumulative total stockholder return on the Successor 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, 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.
Recent Sales of Unregistered Securities None. 38 Table of Contents Inde x to Financial Statements Stock Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
Recent Sales of Unregistered Securities None. 39 Table of Contents Index to Financial Statements Stock Performance Graph The following Performance Graph and related information shall not be deemed “soliciting material” or to be “filed” with the Securities and Exchange Commission, nor shall such information be incorporated by reference into any future filings under the Securities Act of 1933 or Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filings.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Common Stock Shares of our Common Stock are listed on the NYSE under the symbol "GPOR". See Note 7 of our consolidated financial statements for further discussion of our Common Stock.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Common Stock Shares of our common stock are listed on the NYSE under the symbol “GPOR”. See Note 6 of our consolidated financial statements for further discussion of our common stock.
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 $650 million and extended through December 31, 2024.
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.
As of December 31, 2023, the Company had repurchased 4.4 million shares for $399.6 million at a weighted average price of $91.53 per share.
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.
Shareholders At the close of business on February 14, 2024, there were approximately 8,635 holders of record of our Common Stock. Dividends Subsequent to our emergence from bankruptcy, we have not paid dividends on our Common Stock.
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.
Removed
During the Prior Successor Period, the Company paid dividends on our Preferred Stock, which included 3,071 shares of Preferred Stock paid in kind, approximately $55 thousand of cash-in-lieu of fractional shares, and $1.5 million of cash dividends to holders of our Preferred Stock.

Item 6. [Reserved]

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

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Biggest changeITEM 6. RESERVED 39 ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS 39 RESULTS OF OPERATIONS 43 LIQUIDITY AND CAPITAL RESOURCES 48 CRITICAL ACCOUNTING POLICIES AND ESTIMATES 53 ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 55 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 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

Item 7. Management's Discussion & Analysis

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

79 edited+39 added−41 removed26 unchanged
Biggest changeDepreciation, Depletion and Amortization (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Depreciation, depletion and amortization of oil and gas properties $ 318,473 $ 266,449 20 % Depreciation, depletion and amortization of other property and equipment 1,242 1,312 (5) % Total depreciation, depletion and amortization $ 319,715 $ 267,761 19 % Total depreciation, depletion and amortization per Mcfe $ 0.83 $ 0.74 12 % The increase in total and per unit depreciation, depletion and amortization of our oil and gas properties for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily the result of our drilling and development activities subsequent to 2022. 46 Table of Contents Inde x to Financial Statements General and Administrative Expenses (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change General and administrative expenses, gross $ 75,180 $ 68,495 10 % Reimbursed from third parties (13,770) (13,035) 6 % Capitalized general and administrative expenses (22,810) (20,156) 13 % General and administrative expenses, net $ 38,600 $ 35,304 9 % General and administrative expenses, net per Mcfe $ 0.10 $ 0.10 — % The increase in total general and administrative expenses for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily driven by increases in employee headcount and compensation as well as legal expenses related to the continued administration of our Chapter 11 filing and settlement of a firm transportation agreement as noted in Note 19 of our consolidated financial statements.
Biggest changeGeneral 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.
As discussed in Note 6 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 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”).
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 18 of our consolidated financial statements for further discussion of the various financial guarantees we have issued. Capital Expenditures.
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.
The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility from $700 million to $900 million, (b) increased the borrowing base under the Credit Facility from $1 billion to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility from $45 million to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not be refinanced, redeemed or repaid in full on or prior to such 91st day.
The Third Amendment, among other things, (a) increased the aggregate elected commitment amounts under the Credit Facility to $900 million, (b) increased the borrowing base under the Credit Facility to $1.1 billion, (c) increased the excess cash threshold under the Credit Facility to $75 million, and (d) extended the maturity date under the Credit Facility from October 14, 2025 to the earlier of (i) May 1, 2027 and (ii) the 91st day prior to the maturity date of the 2026 Senior Notes or any other permitted senior notes or any permitted refinancing debt under the Credit Facility having an aggregate outstanding principal amount equal to or exceeding $100 million; provided that such notes have not been refinanced, redeemed or repaid in full on or prior to such 91st day.
Business and Industry Outlook The Company's primary focus going into 2024 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 2025 is its continued attention on reducing cycle times and operating costs to improve margins and ultimately support our expected free cash flow generation.
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.
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.
Financial Statements and Supplementary Data” of this report. The following information updates the discussion of Gulfport's financial condition provided in its 2022 Annual Report on Form 10-K filing and compares the results of operations for the year ended December 31, 2023 to the period ended December 31, 2022.
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.
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.
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.
(4) See Note 10 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 13 and 4 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. See Notes 12 and 3 of our consolidated financial statements, respectively. Off-balance Sheet Arrangements.
Additionally, see Note 13 of our consolidated financial statements for further discussion of derivatives and hedging activities.
Additionally, see Note 12 of our consolidated financial statements for further discussion of derivatives and hedging activities.
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 54% of our expected 2024 production, at an average floor price of $3.70 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 46% of our expected 2025 production, at an average floor price of $3.59 per Mcf.
See Note 5 of our consolidated financial statements for a description of our long-term debt. (2) See Note 18 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments. (3) See Note 18 of our consolidated financial statements for a description of our other operational commitments.
See Note 4 of our consolidated financial statements for a description of our long-term debt. (2) See Note 17 of our consolidated financial statements for further discussion of our firm transportation and gathering commitments. (3) See Note 17 of our consolidated financial statements for a description of our other operational commitments.
The fair value gains of our hedging program totaled $588.1 million for the year ended December 31, 2023 compared to $54.1 million for the year ended December 31, 2022. Settlement gains (losses) in the table above represent realized cash gains or losses to the instruments described in Note 13 of our consolidated financial statements.
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.
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2023, our material off-balance sheet arrangements and transactions include $63.8 million in letters of credit outstanding against our Credit Facility and $43.3 million in surety bonds issued.
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.
The realized price change was primarily driven by the decrease in the average Henry Hub gas index from $6.64 per Mcf in the year ended December 31, 2022, to $2.74 per Mcf during the year ended December 31, 2023.
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.
See Note 5 of our consolidated financial statements for additional discussion of our outstanding debt. Preferred Stock Dividends .
See Note 4 of our consolidated financial statements for additional discussion of our outstanding debt. Dividends on Preferred Stock .
Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials spans 2024, with approximately $28.9 million remaining.
Both the letters of credit and surety bonds are being used as financial assurance, primarily for certain firm transportation agreements. Additionally, the Company entered into various contractual commitments to purchase inventory and other material to be used in future activities. The Company's commitment to purchase these materials exists through 2025, with approximately $13.8 million remaining.
Also, we currently expect to spend approximately $50 million to $60 million in 2024 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 2024 and 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.
The material changes that lead 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.
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.
As of December 31, 2023, our net working capital includes no debt due in the next 12 months. Our total principal amount of funded debt as of December 31, 2023, was $668.0 million compared to $695.0 million as of December 31, 2022.
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.
The 9% increase in natural gas production was due to our 2022 and 2023 development programs in the Utica/Marcellus partially offset by natural declines and limited activity in the SCOOP.
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.
We estimate the fair value of all derivative instruments using industry-standard models 54 Table of Contents Inde x to Financial Statements 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.
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.
Henry Hub averaged $2.53 per MMBtu in 2023 vs $6.44 per MMBtu in 2022. As we look into 2024, we expect continued volatility in natural gas prices.
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.
Discussions of 2021 items and comparisons between 2022, Prior Successor Period and Prior Predecessor Period 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, 2022. 39 Table of Contents Inde x 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 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.
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. "Quantitative and Qualitative Disclosures about Market Risk" for further information regarding our open derivative instruments at December 31, 2023.
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.
The decrease in NGL sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 34% decrease in realized prices, partially offset by a 2% decrease in NGL sales volumes.
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 volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions. Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information. Income Taxes.
Changes in natural gas, oil or NGL prices could result in actual results differing significantly from our estimates. See Note 20 of our consolidated financial statements for further information. Income Taxes.
For the year ended December 31, 2023, our primary sources of capital resources and liquidity have consisted of internally generated cash flows from operations, and our primary uses of cash have been for development of our oil and natural gas properties, share repurchases and discretionary acreage acquisitions.
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.
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. 41 Table of Contents Inde x to Financial Statements In 2023, natural gas prices continued to be volatile as spot prices ranged from $1.74 to $3.78 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 2024, natural gas prices continued to be volatile as spot prices ranged from $1.21 to $13.20 per MMBtu.
Our drilling and completion capital expenditures for 2024 are currently estimated to be in the range of $330 million to $360 million.
Our drilling and completion capital expenditures for 2025 are currently estimated to be in the range of $335 million to $355 million.
The significant change in the total gain (loss) for the year ended December 31, 2023 compared to the year ended December 31, 2022, was primarily the result of a significant decrease in futures pricing for oil, natural gas, and NGLs.
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.
As of December 31, 2023, we had $1.9 million of cash and cash equivalents compared to $7.3 million as of December 31, 2022, and a net working capital of $52.4 million as of December 31, 2023, compared to a net working capital deficit of $391.1 million as of December 31, 2022.
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.
The decrease in oil and condensate sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 20% decrease in realized oil prices and a 15% decrease in sales volumes.
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 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC (the “Non-Guarantors”). The Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several.
The 2026 Senior Notes are guaranteed on a senior unsecured basis by all existing consolidated subsidiaries that guarantee our Credit Facility or certain other debt (the “2026 Senior Notes Guarantors”). The 2026 Senior Notes are not guaranteed by Grizzly Holdings or Mule Sky, LLC.
Our hedging program generated cash receipts of $152.2 million for the year ended December 31, 2023, compared to cash settlements of $1,053.8 million for the year ended December 31, 2022.
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.
If this occurs or if our production estimates change or our exploration or 51 Table of Contents Inde x to Financial Statements development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.
This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs or if our production estimates change or our exploration or development activities are curtailed, full cost accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our oil and natural gas properties.
During the year ended December 31, 2023, the Company paid $4.8 million of cash dividends to holders of our Preferred Stock compared to $5.4 million in the year ended December 31, 2022. Other.
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.
Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves. If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
If we maintain the same level of production year over year, the depreciation, depletion and amortization expense may be significantly different if our estimate of remaining reserves or future development costs changes significantly. We review the carrying value of our oil and natural gas properties under the full cost method of accounting prescribed by the SEC on a quarterly basis.
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.
There is no guarantee that the debt or equity capital markets will be available to us on acceptable terms or at all.
Cash capital expenditures for the year ended December 31, 2023 and December 31, 2022, were as follows (in thousands): Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Oil and Natural Gas Property Cash Expenditures: Drilling and completion costs $ 413,258 $ 410,281 Leasehold acquisitions 101,191 32,708 Other 22,911 17,791 Total oil and natural gas property expenditures $ 537,360 $ 460,780 Debt activity, net.
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.
There are no significant restrictions on the ability of the Parent or the Guarantors to obtain funds from each other in the form of a dividend or loan.
The 2026 Senior Notes Guarantors are 100% owned by the Parent, and the guarantees are full, unconditional, joint and several. There are no significant restrictions on the ability of the Parent or the 2026 Senior Notes Guarantors to obtain funds from each other in the form of a dividend or loan.
We use the full cost method of accounting for oil and natural gas operations. Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized.
Accordingly, all costs, including non-productive costs and certain general and administrative costs directly associated with acquisition, exploration and development of oil and natural gas properties, are capitalized. Under the full cost method, capitalized costs are amortized on a composite unit-of-production method based on proved oil and natural gas reserves.
The accuracy of any reserve estimate is a function of the quality of data available and of engineering and geological interpretation and judgment. In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements.
In addition, estimates of reserves may be revised based on actual production, results of subsequent exploration and development activities, recent commodity prices, operating costs and other factors. These revisions could materially affect our financial statements. The volatility of commodity prices results in increased uncertainty inherent in these estimates and assumptions.
For the year ended December 31, 2023, the Company's incurred capital expenditures totaled $491.5 million, of which $388.6 million related to drilling and completion activities, $54.8 million related to maintenance leasehold and land investment and $48.0 million related to discretionary acreage acquisitions.
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.
Transportation, Gathering, Processing and Compression (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Transportation, gathering, processing and compression $ 348,631 $ 357,246 (2) % Transportation, gathering, processing and compression per Mcfe $ 0.91 $ 1.00 (9) % Transportation, gathering, processing and compression for the year ended December 31, 2023, compared to the year ended December 31, 2022, decreased on a per unit basis primarily as a result of lower minimum volume commitments as a result of our 7% increase in production.
Transportation, Gathering, Processing and Compression (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Transportation, gathering, processing and compression $ 351,237 $ 348,631 1 % Transportation, gathering, processing and compression per Mcfe $ 0.91 $ 0.91 — % Transportation, gathering, processing and compression for the year ended December 31, 2024, compared to the year ended December 31, 2023, increased in total primarily as a result of our small increase in production.
Natural Gas, Oil and Condensate and NGL Production and Pricing (sales totals in thousands) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas (MMcf/day) Utica & Marcellus production volumes 766 674 SCOOP production volumes 194 209 Total production volumes 960 883 Total sales $ 831,812 $ 1,998,452 Average price without the impact of derivatives ($/Mcf) $ 2.37 $ 6.20 Impact from settled derivatives ($/Mcf) $ 0.42 $ (3.11) Average price, including settled derivatives ($/Mcf) $ 2.79 $ 3.09 Oil and condensate (MBbl/day) Utica & Marcellus production volumes 1 1 SCOOP production volumes 3 4 Total production volumes 4 4 Total sales $ 99,854 $ 147,444 Average price without the impact of derivatives ($/Bbl) $ 73.27 $ 91.58 Impact from settled derivatives ($/Bbl) $ (2.53) $ (24.32) Average price, including settled derivatives ($/Bbl) $ 70.74 $ 67.26 NGL (MBbl/day) Utica & Marcellus production volumes 2 2 SCOOP production volumes 10 10 Total production volumes 12 12 Total sales $ 119,717 $ 184,963 Average price without the impact of derivatives ($/Bbl) $ 27.29 $ 41.26 Impact from settled derivatives ($/Bbl) $ 2.07 $ (2.80) Average price, including settled derivatives ($/Bbl) $ 29.36 $ 38.46 Total (MMcfe/day) Utica & Marcellus production volumes 784 693 SCOOP production volumes 270 290 Total production volumes 1,054 983 Total sales $ 1,051,383 $ 2,330,859 Average price without the impact of derivatives ($/Mcfe) $ 2.73 $ 6.49 Impact from settled derivatives ($/Mcfe) $ 0.40 $ (2.94) Average price, including settled derivatives ($/Mcfe) $ 3.13 $ 3.55 43 Table of Contents Inde x to Financial Statements Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Natural gas $ 831,812 $ 1,998,452 (58) % Oil and condensate 99,854 147,444 (32) % NGL 119,717 184,963 (35) % Total natural gas, oil and condensate and NGL sales $ 1,051,383 $ 2,330,859 (55) % The decrease in natural gas sales without the impact of derivatives when comparing the year ended December 31, 2023, to the year ended December 31, 2022, was due to a 62% decrease in realized natural gas prices, partially offset by a 9% increase in sales volumes.
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.
Subsequent to December 31, 2023 and as of February 26, 2024, 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) 2024 Swaps NYMEX Henry Hub 40,219 $2.66 2024 Basis Swaps TETCO M2 18,306 $(0.90) 2025 Basis Swaps TETCO M2 100,000 $(0.99) 2025 Costless Collars NYMEX Henry Hub 30,000 $3.25 / $4.03 NGL (Bbl/d) ($/Bbl) 2025 Swaps Mont Belvieu C3 1,000 $30.14 50 Table of Contents Inde x to Financial Statements Contractual and Commercial Obligations.
Subsequent to December 31, 2024 and as of February 20, 2025, we entered into the following natural gas, oil, and NGL derivative contracts: Period Type of Derivative Instrument Index Daily Volume Weighted Average Price Natural Gas (MMBtu/d) ($/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.
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.
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. 48 Table of Contents Index to Financial Statements To the extent actual operating results, realized commodity prices or uses of cash differ from our assumptions, our liquidity could be adversely affected.
To accomplish these goals, we 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. Recent Developments Leadership Changes In January 2023, ou r CEO Tim Cutt, resigned his position as CEO. Mr.
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.
The realized price change was primarily driven by the decrease in the average WTI crude index from $94.23 per barrel in the year ended December 31, 2022, to $77.62 per barrel during the year ended December 31, 2023. The 15% decrease in oil and condensate production was due to natural declines and limited activity in the SCOOP.
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.
Credit Facility On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”).
This resulted in extending the maturity of substantially all of our senior notes from 2026 to 2029. Additionally, on May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Credit Facility.
See Note 5 of our consolidated financial statements for additional discussion of the Credit Facility. On October 27, 2023, Gulfport completed its semi-annual borrowing base redetermination during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
On April 18, 2024, Gulfport completed its semi-annual borrowing base redetermination under its Credit Facility during which the borrowing base was reaffirmed at $1.1 billion with elected commitments remaining at $900 million.
During the year ended December 31, 2023, and the year ended December 31, 2022, the Company paid $4.8 million and $5.4 million, respectively, of cash dividends to holders of our Preferred Stock. 49 Table of Contents Inde x to Financial Statements Supplemental Guarantor Financial Information .
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 .
Sources and Uses of Cash The following table presents the major changes in cash and cash equivalents for the year ended December 31, 2023 and December 31, 2022 (in thousands): Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Net cash provided by operating activities $ 723,181 $ 739,077 Additions to oil and natural gas properties (537,360) (460,780) Debt activity, net (27,000) (19,000) Repurchases of Common Stock (149,165) (250,482) Preferred Stock dividends (4,840) (5,444) Other (10,146) 628 Net change in cash and cash equivalents (5,330) 3,999 Cash and cash equivalents at end of period $ 1,929 $ 7,259 Net cash provided by operating 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.
Successor Year Ended December 31, 2023 Year Ended December 31, 2022 Natural gas derivatives - fair value gains $ 584,563 $ 32,797 Natural gas derivatives - settlement gains (losses) 146,381 (1,002,098) Total gains (losses) on natural gas derivatives 730,944 (969,301) Oil and condensate derivatives - fair value gains 5,971 6,618 Oil and condensate derivatives - settlement losses (3,272) (39,163) Total gains (losses) on oil and condensate derivatives 2,699 (32,545) NGL derivatives - fair value (losses) gains (2,414) 14,648 NGL derivatives - settlement gains (losses) 9,090 (12,549) Total gains on NGL derivatives 6,676 2,099 Total gains (losses) on natural gas, oil and NGL derivatives $ 740,319 $ (999,747) We recognize fair value changes on our natural gas, oil and NGL derivative instruments in each reporting period.
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.
The volatility of the energy markets makes it extremely difficult to predict future oil and natural gas price movements with any certainty. 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. 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.
See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting. 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.
See Oil and Natural Gas Properties in Note 1 of our consolidated financial statements for further information on the full cost method of accounting. 53 Table of Contents Index to Financial Statements Oil, Natural Gas and NGL Reserves.
During the year ended December 31, 2023, the Company repurchased 1.5 million shares for approximately $148.9 million under the Repurchase Program at a weighted average price of $101.53 per share. For the same period in 2022, the Company repurchased 2.9 million shares for $250.8 million at a weighted average price of $86.47 per share.
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.
Additionally, Other, net included a $5.1 million payment to settle certain gas imbalance positions and a $5.2 million receipt of funds from a litigation settlement. Income Taxes (in thousands) For the year ended December 31, 2023, we had an effective tax rate of (56)% and an income tax benefit of $525.2 million.
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.
During the year ended December 31, 2023, we spud 20 gross (17.9 net) wells and commenced sales from 22 gross (20.2 net) wells in the Utica/Marcellus for a total cost of approximately $344.4 million and we spud 5 gross (3.2 net) and commenced sales from 2 gross (1.7 net) wells in the SCOOP for a total cost of approximately $37.3 million.
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.
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, 2023. Downward revisions to estimates of oil and natural gas reserves and/or unfavorable prices can have a material impact on the present value of estimated future net revenues.
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.
Interest Expense (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Interest on 2026 Senior Notes $ 44,000 $ 44,000 — % Interest on Credit Facility 13,810 12,799 8 % Amortization of loan costs 3,256 2,914 12 % Capitalized interest (4,147) — 100 % Other 150 60 150 % Total interest expense $ 57,069 $ 59,773 (5) % Interest expense per Mcfe $ 0.15 $ 0.17 (12) % Interest expense on our Credit Facility increased 8% for the year ended December 31, 2023, compared to the year ended December 31, 2022, as a result of increased interest rates resulting from the current inflationary environment.
Interest Expense (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Interest on 2026 Senior Notes $ 31,417 $ 44,000 (29) % Interest on 2029 Senior Notes 13,163 — 100 % Interest on Credit Facility 14,143 13,810 2 % Amortization of loan costs 4,208 3,256 29 % Capitalized interest (4,771) (4,147) 15 % Other 1,822 150 1115 % Total interest expense $ 59,982 $ 57,069 5 % Interest expense per Mcfe $ 0.16 $ 0.15 7 % Due to the tender offer for the 2026 Senior Notes in the third quarter of 2024 described below, interest paid on the 2026 Senior Notes decreased 29% for the year ended December 31, 2024, compared to the year ended December 31, 2023.
LOE per unit for the year ended December 31, 2023 was consistent with the year ended December 31, 2022. 45 Table of Contents Inde x to Financial Statements Taxes Other Than Income (in thousands, except per unit) Successor Year Ended December 31, 2023 Year Ended December 31, 2022 % Change Production taxes $ 25,564 $ 48,145 (47) % Property taxes 6,160 7,146 (14) % Other 1,993 4,847 (59) % Total taxes other than income $ 33,717 $ 60,139 (44) % Total taxes other than income per Mcfe $ 0.09 $ 0.17 (47) % The decrease in total and per unit taxes other than income for the year ended December 31, 2023, compared to the year ended December 31, 2022, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
Lease Operating Expenses (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Lease operating expenses Utica & Marcellus $ 48,321 $ 44,394 9 % SCOOP 21,791 24,254 (10) % Total lease operating expenses $ 70,112 $ 68,648 2 % Lease operating expenses per Mcfe Utica & Marcellus $ 0.16 $ 0.16 — % SCOOP 0.28 0.25 12 % Total lease operating expenses per Mcfe $ 0.18 $ 0.18 — % The increase in total LOE for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily the result of increased production in Utica/Marcellus as described above. 45 Table of Contents Index to Financial Statements Taxes Other Than Income (in thousands, except per unit) Year Ended December 31, 2024 Year Ended December 31, 2023 % Change Production taxes $ 19,385 $ 25,564 (24) % Property taxes 8,174 6,160 33 % Other 2,178 1,993 9 % Total taxes other than income $ 29,737 $ 33,717 (12) % Total taxes other than income per Mcfe $ 0.08 $ 0.09 (11) % The decrease in total and per unit taxes other than income for the year ended December 31, 2024, compared to the year ended December 31, 2023, was primarily related to a decrease in production taxes resulting from the decrease in our natural gas, oil and NGL revenues excluding the impact of hedges discussed above.
During the year ended December 31, 2023, the Company paid other expenses of $10.1 million, as compared to other expenses of $0.6 million paid during the year ended December 31, 2022.
During the year ended December 31, 2024, the Company incurred other expenses of $1.9 million, as compared to other income of $0.1 million paid during the year ended December 31, 2023. The change was primarily related to proceeds from sales of oil and gas properties of $2.6 million during the year ended December 31, 2023.
The NGL production remained consistent when comparing the year ended December 31, 2023 to the year ended December 31, 2022. 44 Table of Contents Inde x 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, 2023 and 2022, represented approximately 95% and 86%, respectively, of our total sales volumes for the applicable year.
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.
The following table sets forth our contractual and commercial obligations at December 31, 2023 (in thousands): Payment due by period Contractual Obligations Total 2024 2025-2026 2027-2028 2029 and Thereafter Long-term debt (1) : Principal $ 668,000 $ — $ 550,000 $ 118,000 $ — Interest 108,167 44,000 64,167 — — Firm transportation and gathering contracts (2) 1,364,389 219,367 271,985 273,006 600,031 Other operational commitments (3) 28,938 28,938 — — — Operating lease liabilities (4) 14,298 12,958 1,330 10 — Total contractual cash obligations (5) $ 2,183,792 $ 305,263 $ 887,482 $ 391,016 $ 600,031 _____________________ (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, 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.
Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.
Drilling and completion costs discussed above reflect incurred costs while drilling and completion costs presented in the table below reflect cash payments for drilling and completions. Incurred capital expenditures and cash capital expenditures may vary from period to period due to the cash payment cycle.
Other, net included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during our Chapter 11 filing. Other, net in the Company's consolidated statements of operations for the year ended December 31, 2022, included $11.5 million related to the initial TC claim distribution as discussed in Note 19 of our consolidated financial statements.
Other, net in the second quarter of 2023 included a $5.0 million recoupment of previously placed collateral for certain firm transportation commitments during the Company's Chapter 11 Cases. Additionally, in the fourth quarter of 2023, Gulfport received an additional $8.3 million distribution related to its TC claim.
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.
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.
On May 1, 2023, the Company entered into that certain Joinder, Commitment Increase and Borrowing Base Redetermination Agreement, and Third Amendment to Credit Agreement (the “Third Amendment”) which amended the Company’s Existing Credit Facility (as amended, the “Credit Facility”).
On September 12, 2024, the Company entered into the Commitment Increase, Borrowing Base Reaffirmation Agreement, and Fourth Amendment to Credit Agreement (the “Fourth Amendment”), which amended the Company’s Third Amended and Restated Credit Agreement.
Net cash provided by operating activities was $723.2 million for the year ended December 31, 2023, compared to $739.1 million for the year ended December 31, 2022. The decrease was primarily the result of a decrease in revenue due to a decline in commodity prices partially offset by an increase of cash receipts from settled derivative instruments.
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.
During the year ended December 31, 2023, the Company had $971.0 million and $998.0 million in borrowings and repayments, respectively, on its Credit Facility. As of February 26, 2024, the Company had $51.0 million in borrowings outstanding on its Credit Facility. Repurchases of Common Stock.
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.
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 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our 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.
The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company's subsidiaries that guarantee the Credit Facility.
The 2026 Senior Notes are guaranteed on a senior unsecured basis by each of the Company’s subsidiaries that guarantee the Credit Facility. In September 2024, Gulfport Operating purchased approximately 95%, or $524.3 million, of the 2026 Senior Notes in a tender offer using net proceeds received from the private placement of the 2029 Senior Notes.
With the weakening in commodity prices, we could begin to see additional deflationary pressures during 2024 as well as less frequent supply chain constraints. 42 Table of Contents Inde x to Financial Statements Results of Operations Comparison of the Year Ended December 31, 2023 and 2022 We reported net income of $1.5 billion for the year ended December 31, 2023, compared to a net income of 494.7 million for the year ended December 31, 2022.
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.
Any excess of the net book value, less deferred income taxes, is generally written off as an expense. The Company did not record an impairment of its oil and natural gas properties for the year ended December 31, 2023 or December 31, 2022.
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.
During the year ended December 31, 2023, the Company repurchased 1.5 million shares for $148.9 million at a weighted average price of $101.53 per share. As of December 31, 2023, the Company repurchased 4.4 million shares for $399.6 million at a weighted average price of $91.53 per share since the inception of the Repurchase Program.
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.
The ultimate impact of the war in Ukraine and the Israel-Hamas war will depend on future developments and the timing and extent to which normal economic and operating conditions resume. 2023 Operational and Financial Highlights During 2023, we had the following notable achievements: • Reported total net production of 1,054 MMcfe per day. • Generated $723.2 million of operating cash flows. • Turned to sales 24 gross (21.9 net) wells, which included our first two operated Marcellus wells. • Total lease operating expenses, midstream costs and taxes other than income per Mcfe decreased 13%. • Expanded common share repurchase program to $650 million and returned $148.9 million to shareholders through the repurchase of 1.5 million shares at a weighted average price of $101.53 per share. • Reduced total debt by $27 million. • Achieved MIQ certification for all Appalachian assets. • Reported year-end estimated net proved reserves of 4.2 Tcfe.
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.
See Note 5 of our consolidated financial statements for further discussion of our debt obligations, including principal and carrying amounts of our notes. 48 Table of Contents Inde x to Financial Statements As of February 26, 2024, we had $7.1 million of cash and cash equivalents, $51.0 million borrowings under our Credit Facility, $63.8 million of letters of credit outstanding, and $550 million of outstanding 2026 Senior Notes.
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.
Removed
Cutt, who served as CEO and Chairman since 2021, retained his position of Chairman of the Board of Directors. Subsequent to Mr. Cutt's resignation, Gulfport named John Reinhart President and CEO and Director, effective January 24, 2023. In addition, Matthew Rucker joined Gulfport's leadership team as Senior Vice President of Operations.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

12 edited+1 added−0 removed14 unchanged
Biggest changeOur 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. At December 31, 2023, we had a net asset derivative position of $240.2 million, compared to a net liability derivative position of $347.9 million as of December 31, 2022.
Biggest changeAt 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.
The Company enters into International Swap Dealers Association Master Agreements ("ISDA") with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract.
The Company enters into International Swap Dealers Association Master Agreements (“ISDA”) with each of its derivative counterparties prior to executing derivative contracts. The terms of the ISDA provide, among other things, the Company and the counterparties with rights of set-off upon the occurrence of defined acts of default by either the Company or counterparty to a derivative contract.
However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 13 of our consolidated financial statements. Counterparty Credit Risk.
However, any realized derivative gain or loss would be substantially offset by a decrease or increase, respectively, in the actual sales value of production covered by the derivative instrument. For more information regarding the Company's commodity derivative transactions, refer to Note 12 of our consolidated financial statements. Counterparty Credit Risk.
The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 16 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
The values we report in our financial statements are as of a point in time and subsequently change as these estimates are revised to reflect actual results, changes in market conditions and other factors. See Note 15 of our consolidated financial statements for further discussion of the fair value measurements associated with our derivatives.
As of December 31, 2023, 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, 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.
In exchange for higher fixed prices on certain of our swap trades, we may sell call options. 55 Table of Contents Inde x to Financial Statements • Basis Swaps : These instruments are arrangements that guarantee a fixed price differential to NYMEX from a specified delivery point.
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.
At December 31, 2023, we had $118.0 million in borrowings outstanding under our Credit Facility which bore interest at the weighted average rate of 8.15% for the year ended December 31, 2023. A 1% increase in the average interest rate would increase interest expense by approximately $1.2 million based on outstanding borrowings under our Credit Facility at December 31, 2023.
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.
As of December 31, 2023, we did not have any interest rate swaps to hedge our interest risks. 56 Table of Contents Inde x to Financial Statements
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
Utilizing actual derivative contractual volumes, a 10% increase in underlying commodity prices would have decreased our asset by approximately $88.3 million, while a 10% decrease in underlying commodity prices would have increased our asset by approximately $86.5 million.
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.
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. If the market price settles below the fixed price of the call option, no payment is due from either party.
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.
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.
We 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.
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.
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.
Added
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.

Other GPOR 10-K year-over-year comparisons