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What changed in SANDRIDGE ENERGY INC's 10-K — 2024 vs 2025

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

+248 added−273 removedSource: 10-K (2026-03-05) vs 10-K (2025-03-11)

Top changes in SANDRIDGE ENERGY INC's 2025 10-K

248 paragraphs added · 273 removed · 192 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

69 edited+14 added−47 removed146 unchanged
Biggest changeThe following table provides a reconciliation of our PV-10 to Standardized Measure: December 31, 2024 2023 (In thousands) PV-10 $ 362,696 $ 296,293 Present value of future income tax discounted at 10% $ — $ — Standardized Measure of Discounted Net Cash Flows $ 362,696 $ 296,293 Proved Reserves - Mid-Continent .
Biggest changeThe following table provides a reconciliation of our PV-10 to Standardized Measure: Year Ended December 31, 2025 2024 (In thousands) PV-10 $ 439,568 $ 362,696 Present value of future income tax discounted at 10% — — Standardized Measure of Discounted Net Cash Flows $ 439,568 $ 362,696 Proved Reserves - Proved reserves increased from 63.1 MMBoe at December 31, 2024 to 69.1 MMBoe at December 31, 2025, due to extensions of 7.3 MMBoe, purchases of 1.7 MMBoe, positive net revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations and 4.5 MMBoe associated with other commercial improvements.
We could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations due to these frequent changes in the regulatory definition of WOTUS and regulatory uncertainty while litigation is pending.
We could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations due to frequent changes in the regulatory definition of WOTUS and regulatory uncertainty while litigation is pending.
For additional information regarding changes in proved reserves during each of the three years ended December 31, 2024, 2023 and 2022 see “Note 20—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report. 11 Table of Contents Production and Price History The following table includes information regarding our net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.
For additional information regarding changes in proved reserves during each of the three years ended December 31, 2025, 2024 and 2023 see “Note 20—Supplemental Information on Oil and Natural Gas Producing Activities” to the accompanying consolidated financial statements in Item 8 of this report. 11 Table of Contents Production and Price History The following table includes information regarding our net oil, natural gas and NGL production and certain price and cost information for each of the periods indicated.
A copy of the report issued by our independent reserve consultant with respect to our oil, natural gas and NGL reserves as of December 31, 2024 is filed with this report as Exhibit 99.1. Cawley, Gillespie & Associates prepared reserves for our Mid-Continent properties located in Kansas, Oklahoma, and Texas as of December 31, 2024.
A copy of the report issued by our independent reserve consultant with respect to our oil, natural gas and NGL reserves as of December 31, 2025 is filed with this report as Exhibit 99.1. Cawley, Gillespie & Associates prepared reserves for our Mid-Continent properties located in Kansas, Oklahoma, and Texas as of December 31, 2025.
Climate Change In December 2009, the EPA published its findings that emissions of CO 2 , methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
Climate Change In December 2009, the EPA published its findings that emissions of CO 2 , methane and certain other “greenhouse gases” ("GHGs") present an endangerment to public health and the environment (the “Endangerment Finding”) because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown on page 10 below. (2) Average daily net production for the year ended December 31, 2024.
All prices are held constant throughout the lives of the properties. The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown on page 10 below. (2) Average daily net production for the year ended December 31, 2025.
(2) Represents production costs per Boe excluding production and ad valorem taxes. Productive Wells The following table presents the number of productive wells in which we owned a working interest at December 31, 2024. We operate the majority of all wells in which we owned a working interest at December 31, 2024 and 2023.
(2) Represents production costs per Boe excluding production and ad valorem taxes. Productive Wells The following table presents the number of productive wells in which we owned a working interest at December 31, 2025. We operate the majority of all wells in which we owned a working interest at December 31, 2025 and 2024.
Most states, and some counties, municipalities and Native American tribal areas where we operate regulate one or more of the following activities: • the location of wells; 22 Table of Contents • the method of drilling and casing wells; • the timing of construction or drilling activities; • the rates of production, or “allowables”; • the use of surface or subsurface waters; • the surface use and restoration of properties upon which wells are drilled; • the plugging and abandoning of wells; and • the notice to surface owners and other third parties.
Most states, and some counties, municipalities and Native American tribal areas where we operate regulate one or more of the following activities: • the location of wells; • the method of drilling and casing wells; • the timing of construction or drilling activities; • the rates of production, or “allowables”; • the use of surface or subsurface waters; • the surface use and restoration of properties upon which wells are drilled; • the plugging and abandoning of wells; and • the notice to surface owners and other third parties.
We are not aware of any incidents, citations or suits related to our hydraulic fracturing activities involving material environmental concerns. OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes.
We are not aware of any incidents, citations or suits related to our hydraulic fracturing activities involving material environmental concerns. 20 Table of Contents OTHER REGULATION OF THE OIL AND NATURAL GAS INDUSTRY The oil and natural gas industry is extensively regulated by numerous federal, state, local, and regional authorities, as well as Native American tribes.
These are SEC prices calculated by using trailing 12 month average from the first trading day close of each calendar month. (b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and excludes any impact of derivatives.
These are SEC prices calculated by using trailing 12 month averages from the first trading day close of each calendar month. (b) Average adjusted volume-weighted wellhead product prices reflect adjustments for transportation, quality, gravity, regional price differentials and exclude any impact of derivatives.
Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.
Facilities required to obtain PSD permits for their GHG emissions also are required to meet “best available control technology” standards that could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds.
The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production.
The FERC’s regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation of oil and natural gas. 21 Table of Contents Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production.
Based on its findings, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.
Based on the Endangerment Finding, the EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.
CGA and the Reservoir Engineering Manager monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected. 8 Table of Contents We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.
CGA and the Reservoir Engineering Manager monitor well performance and make reserve estimate adjustments as necessary to ensure the most current information is reflected. We encourage ongoing professional education for our engineers and analysts on new technologies and industry advancements as well as refresher training on basic skill sets.
Preparation of Reserves Estimates Approximately 97.5 percent of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No.
Preparation of Reserves Estimates Approximately 97.9% of the proved oil, natural gas and NGL reserves disclosed in this report have been independently prepared by Cawley, Gillespie & Associates (“CGA”), a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693.
Reporting of Natural Gas Liquids NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2024, NGLs comprised approximately 33% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs.
Reporting of Natural Gas Liquids NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2025, NGLs comprised approximately 35.4% of total proved reserves on a barrel equivalent basis and represented volumes to be produced from properties where we have contracts in place for the extraction and sale of NGLs.
Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 37 years of practical experience in petroleum engineering, with over 35 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr.
Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 38 years of practical experience in petroleum engineering, with over 36 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr.
Marketing We sell our oil, natural gas and NGLs to a variety of customers, including oil and natural gas companies and trading and energy marketing companies. We had two purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2024.
Marketing We sell our oil, natural gas and NGLs to a variety of customers, including oil and natural gas companies and trading and energy marketing companies. We had three purchasers that each individually accounted for more than 10% of our total revenue during the year ended December 31, 2025.
Allen graduated from the University of Oklahoma with a Master’s in Business Administration. Mr. Allen has over 15 years of practical experience in petroleum engineering with 10 of those years having been spent in the estimation and evaluation of reserves. Since 2016, Mr.
Allen graduated from the University of Oklahoma with a Master’s in Business Administration. Mr. Allen has over 16 years of practical experience in petroleum engineering with 11 of those years having been spent in the estimation and evaluation of reserves. Since 2016, Mr.
The final New Source Performance Standards and Emission Guidelines for Existing Sources for the Crude Oil and Natural Gas Source Category rule was published on March 8, 2024.
On March 8, 2024, the EPA published final New Source Performance Standards and Emission Guidelines for Existing Sources for the Crude Oil and Natural Gas Source Category.
F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 24, 2025, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr.
Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 20, 2026, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr.
During 2024, our experience and continuing focus on workplace safety has enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe. 24 Table of Contents
During 2025, our experience and continuing focus on workplace safety has enabled us to preserve business continuity without sacrificing our commitment to keeping our colleagues and workplace visitors safe. 23 Table of Contents
In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the EPA Quad Oa requirements.
Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and natural gas operations on federal lands that are substantially similar to the EPA Quad Oa requirements.
The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information and property ownership interests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers.
The technologies and economic data used to estimate the Company’s proved reserves include, but are not limited to, production data, historical price and cost information, property ownership, well logs, geologic maps and well tests. This data was reviewed by various levels of management for accuracy before consultation with independent reserve engineers.
(3) Estimated proved reserves as of December 31, 2024 divided by net production for the year ended December 31, 2024. (4) Average economic reserve life using SEC prices and weighted for reserve volumes at December 31, 2024. Properties Mid-Continent We held interests in 561,831 gross (371,748 net) leasehold acres located primarily in Oklahoma, Kansas, and Texas at December 31, 2024.
(3) Estimated proved reserves as of December 31, 2025 divided by net production for the year ended December 31, 2025. (4) Average economic reserve life using SEC prices and weighted for reserve volumes at December 31, 2025. Properties Mid-Continent We held interests in 574,599 gross (378,537 net) leasehold acres located primarily in Oklahoma, Kansas, and Texas at December 31, 2025.
Associated proved reserves at December 31, 2024 totaled 63.1 MMBoe. Our interests in the Mid-Continent as of December 31, 2024 included 1,465 gross (848 net) producing wells with an average working interest of 57.9%. The interests are largely aggregated across the Mississippian Lime, Meramec and Cherokee formations.
Associated proved reserves at December 31, 2025 totaled 69.1 MMBoe. Our interests in the Mid-Continent as of December 31, 2025 included 1,446 gross (825 net) producing wells with an average working interest of 57.1%. The interests are largely aggregated across the Mississippian Lime, Meramec and Cherokee formations.
We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations. HUMAN CAPITAL As of December 31, 2024, we had 104 full-time employees, including 85 field employees and 19 corporate employees.
We are not able at this time to predict the effects of these regulations or FERC proceedings, if any, on the transportation costs associated with crude oil production from our crude oil producing operations. 22 Table of Contents HUMAN CAPITAL As of December 31, 2025, we had 102 full-time employees, including 82 field employees and 20 corporate employees.
(2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes. 10 Table of Contents (3) PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties.
All prices are held constant throughout the lives of the properties. (2) Standardized Measure differs from PV-10 as standardized measure includes the effect of future income taxes. (3) PV-10 is a non-GAAP financial measure. Neither PV-10 nor Standardized Measure represents an estimate of fair market value of our oil and natural gas properties.
State and Other Regulation The states in which we operate, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas.
We do not believe that compliance with applicable laws and regulations relating to worker health and safety will have a material adverse effect on our business and results of operations. 19 Table of Contents State and Other Regulation The states in which we operate, along with some municipalities and Native American tribal areas, regulate some or all of the following activities: the drilling for, and the production and gathering of, oil and natural gas, including requirements relating to drilling permits, the location, spacing and density of wells, unitization and pooling of interests, the method of drilling, casing and equipping of wells, the protection of fresh water sources, the orderly development of common sources of supply of oil and natural gas, the operation of wells, allowable rates of production, the use of fresh water in oil and natural gas operations, saltwater injection and disposal operations, the plugging and abandonment of wells and the restoration of surface properties, the prevention of waste of oil and natural gas resources, the protection of the correlative rights of oil and natural gas owners and, where necessary to avoid unfair, unjust or discriminatory service, the fees, terms and conditions for the gathering of natural gas.
December 31, 2024 2023 Estimated Proved Reserves (1) Developed Oil (MMBbls) 7.9 7.1 Natural gas (Bcf) 183.6 194.4 NGL (MMBbls) 18.5 16.2 Total proved developed (MMBoe) 57.0 55.7 Undeveloped Oil (MMBbls) 1.9 — Natural gas (Bcf) 12.3 — NGL (MMBbls) 2.2 — Total proved undeveloped (MMBoe) 6.1 — Total Proved Oil (MMBbls) 9.7 7.1 Natural gas (Bcf) 195.9 194.4 NGL (MMBbls) 20.7 16.2 Total proved (MMBoe) 63.1 55.7 Standardized Measure of Discounted Net Cash Flows (in millions) (2) $ 362.7 $ 296.3 PV-10 (in millions) (3) $ 362.7 $ 296.3 ____________________ (1) Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices.
Year Ended December 31, 2025 2024 Estimated Proved Reserves (1) Developed Oil (MMBbls) 8.2 7.9 Natural gas (Bcf) 184.1 183.6 NGL (MMBbls) 21.4 18.5 Total proved developed (MMBoe) 60.3 57.0 Undeveloped Oil (MMBbls) 2.8 1.9 Natural gas (Bcf) 18.2 12.3 NGL (MMBbls) 3.0 2.2 Total proved undeveloped (MMBoe) 8.8 6.1 Total Proved Oil (MMBbls) 11.0 9.7 Natural gas (Bcf) 202.3 195.9 NGL (MMBbls) 24.5 20.7 Total proved (MMBoe) 69.1 63.1 Standardized Measure of Discounted Net Cash Flows (in millions) (2) $439.6 $362.7 PV-10 (in millions) (3) $439.6 $362.7 ___________________ (1) Estimated proved reserves, PV-10 and Standardized Measure were determined using SEC prices, and do not reflect actual prices received or current market prices.
In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing.
In addition, the EPA has adopted rules requiring the reporting of GHG emissions from oil and natural gas production and processing facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic fracturing. 17 Table of Contents On August 1, 2025, the EPA proposed rescinding the Endangerment Finding.
In addition, on December 2, 2023, the EPA announced a final rule under the CAA to reduce methane emissions from the oil and natural gas industry. This final rule is discussed in the Climate Change subsection below.
In addition, on March 8, 2024, the EPA published a final rule under the CAA to reduce methane emissions from the oil and natural gas industry. This final rule is discussed in the Climate Change subsection below.
We had 102 full-time employees, including 87 field employees and 15 corporate employees at December 31, 2023. Health, Safety and Environment Our people are a key driver to our success in Health, Safety and Environment ("HSE") related outcomes.
We had 104 full-time employees, including 85 field employees and 19 corporate employees at December 31, 2024. Health, Safety and Environment Our people are a key driver to our success in Health, Safety and Environment ("HSE") related outcomes.
During the year ended December 31, 2023 there were two operated wells drilled and four wells completed, with zero wells awaiting completion at year end 2023. Developed and Undeveloped Acreage The following table presents information regarding our developed and undeveloped acreage at December 31, 2024.
Additionally, four non-operated wells were drilled and completed during 2025. During the year ended December 31, 2024, there were no operated wells drilled, three operated wells and one non-operated well completed with zero wells awaiting completion at year end 2024. Developed and Undeveloped Acreage The following table presents information regarding our developed and undeveloped acreage at December 31, 2025.
Year Ended December 31, 2024 2023 2022 Production data (in thousands) Oil (MBbls) 918 1,047 949 Natural gas (MMcf) 19,488 20,403 21,101 NGL (MBbls) 1,889 1,705 1,997 Total volumes (MBoe) 6,056 6,152 6,463 Average daily total volumes (MBoe/d) 16.5 16.9 17.7 Average prices—as reported (1) Oil (per Bbl) $ 74.31 $ 74.69 $ 92.21 Natural gas (per Mcf) $ 1.10 $ 1.71 $ 4.88 NGL (per Bbl) $ 18.87 $ 20.83 $ 31.88 Total (per Boe) $ 20.69 $ 24.16 $ 39.34 Expenses per Boe Production costs (2) $ 6.61 $ 6.80 $ 6.39 __________________ (1) Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.
Year Ended December 31, 2025 2024 2023 Production data (in thousands) Oil (MBbls) 1,214 918 1,047 Natural gas (MMcf) 19,802 19,488 20,403 NGL (MBbls) 2,254 1,889 1,705 Total volumes (MBoe) 6,768 6,056 6,152 Average daily total volumes (MBoe/d) 18.5 16.5 16.9 Average prices—as reported (1) Oil (per Bbl) $ 63.64 $ 74.31 $ 74.69 Natural gas (per Mcf) $ 2.10 $ 1.10 $ 1.71 NGL (per Bbl) $ 16.64 $ 18.87 $ 20.83 Total (per Boe) $ 23.10 $ 20.69 $ 24.16 Expenses per Boe Production costs (2) $ 5.35 $ 6.61 $ 6.80 __________________ (1) Prices represent actual average prices for the periods presented and do not include effects of derivative transactions.
Among these executive orders was the Declaring a National Energy Emergency, an order which seeks to stimulate the development of domestic energy resources, including oil and gas.
President Trump issued a series of executive orders on January 20, 2025. Among these executive orders was the Declaring a National Energy Emergency, an order which seeks to stimulate the development of domestic energy resources, including oil and gas.
Moreover, any future changes to regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations. 16 Table of Contents President Trump issued a series of executive orders on January 20, 2025.
Moreover, any future changes to regulations concerning the definition of WOTUS may result in an expansion of the scope of the CWA’s jurisdiction, and we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas or other WOTUS in connection with our operations.
Specifically, the Inflation Reduction Act provides that the Waste Emissions Charge applies to methane from certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the Greenhouse Gas Reporting Program, beginning with methane emissions reported in calendar year 2024.
Furthermore, the Inflation Reduction Act established a Waste Emissions Charge that applies to methane from certain oil and gas facilities that report emissions of more than 25,000 metric tons of carbon dioxide equivalent per year to the EPA's Greenhouse Gas Reporting Program.
These independently developed reserve estimates are presented to the Audit Committee of the Board of Directors ("Audit Committee"). In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves.
These independently developed reserve estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also periodically meets with the independent petroleum consultants that prepare estimates of proved reserves. The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the table below.
The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of economic assumptions; and • the judgment of the personnel preparing the estimates.
The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of economic assumptions; and • the judgment of the personnel preparing the estimates. 8 Table of Contents The Reservoir Engineering Manager serves as the primary technical professional providing oversight of our reserve estimate.
Part 60 for optical gas imaging. Notably, the rule phases out and will eventually ban routine flaring of natural gas produced by newly constructed wells, and requires frequent monitoring and repair of leaks. The Company does not currently conduct routine flaring.
Part 60 for optical gas imaging. Notably, the rule phases out and will eventually ban routine flaring of natural gas produced by newly constructed wells, and requires frequent monitoring and repair of leaks. The Company does not currently conduct routine flaring. This rule and any future revisions thereto will continue to require oil and gas operators to expend material sums.
Estimated Proved Reserves (MMBoe) (1) Daily Production (MBoe/d)(2) Reserves/ Production (Years)(3) Weighted Average Economic Reserve Life (Years)(4) Gross Acreage Net Acreage Geographic Area Mid-Continent 63.1 16.5 10.4 31.6 561,831 371,748 ____________________ (1) Estimated proved reserves were determined using SEC prices, and do not reflect actual prices received or current market prices.
Estimated Proved Reserves (MMBoe) (1) Daily Production (MBoe/d)(2) Reserves/ Production (Years)(3) Weighted Average Economic Reserve Life (Years)(4) Gross Acreage Net Acreage Geographic Area Mid-Continent 69.1 18.5 10.2 35.0 574,599 378,537 ____________________ (1) Estimated proved reserves were determined using SEC prices, and do not reflect actual prices received or current market prices.
The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. We have developed and implemented SPCC plans for properties as required under the CWA.
The OPA also subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill.
The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017. 21 Table of Contents Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain.
Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic fracturing process but, at this time, federal legislation related to hydraulic fracturing appears uncertain.
Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee. To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.
To establish reasonable certainty with respect to our estimated proved reserves, the independent and internal reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability.
The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties in excess of one million dollars per day per violation. 23 Table of Contents The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we or our purchasers may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity.
The FERC also regulates interstate natural gas transportation rates and service conditions and establishes the terms under which we or our purchasers may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and release of our natural gas pipeline capacity.
In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.
In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.
Developed Acreage Undeveloped Acreage Gross Net Gross Net Geographic Area Mid-Continent 485,789 334,479 76,042 37,269 12 Table of Contents 43% of leases that expire included in the net undeveloped acreage above will expire at the end of their respective primary terms.
Developed Acreage Undeveloped Acreage Gross Net Gross Net Geographic Area Mid-Continent 491,197 337,623 83,402 40,914 12 Table of Contents 40% of leases that expire included in the net undeveloped acreage above will expire at the end of their respective primary terms.
State agencies in Kansas, Oklahoma, and Texas impose financial assurance requirements on operators. The Corps and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Natural Gas Sales and Transportation The availability, terms and cost of transportation significantly affect sales of oil and natural gas.
State agencies in Kansas, Oklahoma, and Texas impose financial assurance requirements on operators. The Corps and many other state and local authorities also have regulations for plugging and abandonment (including regulations that may arise out of Oklahoma's Senate Bill 131), decommissioning and site restoration.
The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below: Index prices (a) Weighted average wellhead prices (b) Oil (per Bbl) Natural gas (per MMBtu) Oil (per Bbl) NGL (per Bbl) Natural gas (per Mcf) December 31, 2024 $ 75.48 $ 2.13 $ 74.04 $ 19.40 $ 1.02 December 31, 2023 $ 78.22 $ 2.64 $ 76.65 $ 21.53 $ 1.62 ____________________ (a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.
PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities. 10 Table of Contents The index prices and the equivalent weighted average wellhead prices used in the reserve reports are shown in the table below: Index prices (a) Weighted average wellhead prices (b) Oil (per Bbl) Natural gas (per MMBtu) Oil (per Bbl) NGL (per Bbl) Natural gas (per Mcf) December 31, 2025 $ 65.34 $ 3.39 $ 64.15 $ 17.13 $ 2.07 December 31, 2024 $ 75.48 $ 2.13 $ 74.04 $ 19.40 $ 1.02 ____________________ (a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.
While there has not been a material impact on our ability to produce operated wells historically, changes in regulatory action or enforcement could have a material adverse impact on the wells we operate or participate in. 17 Table of Contents Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed.
Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed.
These were partially offset by negative revisions including 6.6 MMBoe due to a decrease in year-end SEC commodity prices for oil and natural gas and price realizations, as well as 6.1 MMBoe from the Company’s production during 2024, and 1.7 MMboe attributable to well performance, well shut-ins and other revisions.
These were partially offset by negative revisions including 6.8 MMBoe from the Company’s production during 2025, and 3.1 MMBoe attributable to the decrease in SEC oil pricing, well shut-ins and other revisions.
A critical habitat designation could result in further material restrictions to federal and private land use and could delay or prohibit land access or development. 20 Table of Contents Employee Health and Safety Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes and regulations, whose purpose is to protect the health and safety of workers.
Employee Health and Safety Our operations are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act (“OSHA”), and comparable state statutes and regulations, whose purpose is to protect the health and safety of workers.
As of December 31, 2024, we had an interest in 1,465 gross (848 net) producing wells, approximately 956 of which we operate, and 561,831 gross (371,748 net) total acres under lease. As of December 31, 2024, we had no active drilling rigs. Total estimated proved reserves as of December 31, 2024, were 63.1 MMBoe.
As of December 31, 2025, we had an interest in 1,446 gross (825 net) producing wells, approximately 930 of which we operate, and 574,599 gross (378,537 net) total acres under lease. As of December 31, 2025, we had one active drilling rig. Total estimated proved reserves as of December 31, 2025, were 69.1 MMBoe.
The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the table below. December 31, 2024 2023 Cawley, Gillespie & Associates, Inc. 97.5 % 95.2 % Total 97.5 % 95.2 % The remaining 2.5% and 4.8% of estimated proved reserves as of December 31, 2024 and 2023 were based on internally prepared estimates.
Year Ended December 31, 2025 2024 Cawley, Gillespie & Associates, Inc. 97.9 % 97.5 % Total 97.9 % 97.5 % The remaining 2.1% and 2.5% of estimated proved reserves as of December 31, 2025 and 2024 were based on internally prepared estimates.
These were partially offset by negative revisions including 6.6 MMBoe due to a decrease in year-end SEC commodity prices for oil and natural gas and price realizations, as well as 6.1 MMBoe from the Company’s production during 2024, and 1.7 MMboe attributable to well performance, well shut-ins and other revisions.
These were partially offset by a decrease in SEC oil pricing, 6.8 MMBoe from the Company’s production during 2025, and 3.9 MMBoe attributable to performance, well shut-ins and other revisions.
Reserve Quantities, PV-10 and Standardized Measure The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2024 and 2023, of which approximately 97.5% and 95.2%, respectively, were prepared by independent reserve engineers. 9 Table of Contents See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.
All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs. 9 Table of Contents Reserve Quantities, PV-10 and Standardized Measure The following estimates of proved oil, natural gas and NGL reserves are based on reserve reports as of December 31, 2025 and 2024, of which approximately 97.9% and 97.5%, respectively, were prepared by independent reserve engineers.
As of December 31, 2024, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows: Acres Expiring Gross Net Twelve Months Ending December 31, 2025 160 64 December 31, 2026 5,709 4,035 December 31, 2027 16,378 11,842 December 31, 2028 and later — — Total (1) 22,247 15,941 ____________________ (1) The Company has 53,795 gross (21,328 net) undeveloped acres not subject to expiration.
As of December 31, 2025, the gross and net acres subject to leases in the undeveloped acreage above are set to expire as follows: Acres Expiring Gross Net Twelve Months Ending December 31, 2026 2,579 1,727 December 31, 2027 16,062 12,915 December 31, 2028 5,198 1,857 Total (1) 23,839 16,499 ____________________ (1) The Company has 59,563 gross (24,415 net) undeveloped acres not subject to expiration.
Subsurface Injections Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities.
Under the SDWA, the EPA established the Underground Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs regulating underground injection activities.
Oil Natural Gas Total Gross Net Gross Net Gross Net Geographic Area Mid-Continent 1,153 654 312 194 1,465 848 Drilling Activity During the year ended December 31, 2024 there were no operated wells drilled, three operated wells and one non-operated well completed with zero wells awaiting completion at year end 2024.
Oil Natural Gas Total Gross Net Gross Net Gross Net Geographic Area Mid-Continent 1,142 635 304 190 1,446 825 Drilling Activity During the year ended December 31, 2025, the Company operated one drilling rig and drilled seven operated wells and completed six wells with one well drilling and another well awaiting completion as of December 31, 2025.
The scope of EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations. The EPA issued a final rule in September 2015 that attempted to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) under Section 404 of the CWA.
The scope of the EPA’s and the Corps’ regulatory authority under Section 404 of the CWA has been the subject of extensive litigation and frequently changing regulations.
Part 60, Subpart OOOOc for states to follow in developing and implementing state plans to establish performance standards to limit methane emissions from existing sources; finalizing actions stemming from the joint resolution of Congress, adopted on June 30, 2021 discussed above, including creating the proposed "super emitter program”; and finalizing a protocol under 40 C.F.R.
Part 60, Subpart OOOOc for states to follow in developing and implementing state plans to establish performance standards to limit methane emissions from existing sources; establishing a "super emitter program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event”; and finalizing a protocol under 40 C.F.R.
Proved developed Reserves - Proved Developed reserves increased from 55.7 MMBoe at December 31, 2023 to 57.0 MMBoe at December 31, 2024, primarily due to purchases of 9.9 MMBoe, 3.5 MMBoe associated with other commercial improvements. and positive revisions of 2.3 MMBoe related to NGL Yield.
Proved Developed Reserves - Proved developed reserves increased from 57.0 MMBoe at December 31, 2024 to 60.3 MMBoe at December 31, 2025, primarily due to positive revisions of 3.2 MMBoe due to an increase in year-end SEC natural gas pricing and price realizations, extensions of 0.8 MMBoe, 4.7 MMBoe of proved undeveloped ("PUD") converted to proved developed ("PDP") reserves in 2025 under our Cherokee play development program and 4.5 MMBoe associated with other commercial improvements.
We will also remain vigilant for opportunistic, value-accretive acquisitions and business combinations, with consideration of our balance sheet and commitment to our planned return of capital program. 6 Table of Contents PRIMARY BUSINESS OPERATIONS A comparative discussion of our 2023 to 2022 operating results can be found in Item 1 “Business” included in our Annual Report on Form 10-K for the year ended December 31, 2023 filed with the SEC on March 7, 2024.
We will also remain vigilant for opportunistic, value-accretive acquisitions and business combinations, with consideration of our balance sheet and commitment to our planned return of capital program. 6 Table of Contents PRIMARY BUSINESS OPERATIONS Our primary operations are the production, development and acquisition of hydrocarbon resources. The following table presents information concerning our operations as of December 31, 2025.
It is not possible at this time to predict how or if the United States or states might impose further restrictions on GHGs.
Although some states and local governments remain committed to the principles of the Paris Agreement, the executive order could serve as a catalyst for potential agency action relevant to our business. 18 Table of Contents It is not possible at this time to predict how or if the United States or states might impose further restrictions on GHGs.
Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level. We diligently review best practices and industry standards and comply with all regulatory requirements in the protection of potable water sources.
We diligently review best practices and industry standards and comply with all regulatory requirements in the protection of potable water sources.
Proved Undeveloped Reserves - Proved undeveloped reserves increased from 0.0 MMBoe at December 31,2023 to 6.1 MMBoe at December 31, 2024 due to purchases.
Proved Undeveloped Reserves - Proved undeveloped reserves increased from 6.1 MMBoe at December 31, 2024 to 8.8 MMBoe at December 31, 2025 due to extensions of 6.5 MMBoe and purchases of 1.7 MMBoe. There were PUD to PDP conversions of 4.7 MMBoe from five operated and four non-operated wells drilled and turned online in 2025.
On August 21, 2023, the EPA announced a new review of the ozone National Ambient Air Quality Standards and stated that it will incorporate the ongoing reconsideration into this review. EPA also announced that it will consider the advice and recommendation of the ozone review panel of the Clean Air Scientific Advisory Committee ("CASAC") in its review.
On December 31, 2020, the EPA published its decision to retain the 2015 ozone standards; however, on August 21, 2023, the EPA announced a new review of the ozone National Ambient Air Quality Standards.
That information is generally available to employees, state and local governmental authorities, and the public. We do not believe that compliance with applicable laws and regulations relating to worker health and safety will have a material adverse effect on our business and results of operations.
That information is generally available to employees, state and local governmental authorities, and the public.
Removed
Our primary operations are the production, development and acquisition of hydrocarbon resources. The following table presents information concerning our operations as of December 31, 2024.
Added
Allen's preparation of the reserve estimates, those estimates are further reviewed by the executive team and the Audit Committee (the “Audit Committee”) of the Board of Directors of the Company (the “Board”) .
Removed
The Reservoir Engineering Manager serves as the primary technical professional providing oversight of our reserve estimate.
Added
See “Critical Accounting Policies and Estimates” in Item 7 of this report for further discussion of uncertainties inherent to the reserves estimates.
Removed
All production information related to natural gas is reported net of the effect of any reduction in natural gas volumes resulting from the processing and extraction of NGLs.
Added
The company invested $43.7 million to convert these reserves to PDP. Total increase to proved undeveloped reserves were also partially offset by 0.8 MMBoe attributable to other negative revisions including the decrease in SEC oil pricing.
Removed
All prices are held constant throughout the lives of the properties.
Added
The EPA issued a proposed rule in November 2025 to clarify the federal jurisdictional reach over waters of the United States (“WOTUS”) under Section 404 of the CWA, which is expected to be challenged in litigation once finalized.
Removed
PV-10 is used by the industry and by management as a reserve asset value measure to compare against past reserve bases and the reserve bases of other business entities.
Added
We have developed and implemented SPCC plans for properties as required under the CWA. 16 Table of Contents Subsurface Injections Underground injection operations performed by us are subject to the Safe Drinking Water Act (“SDWA”), as well as analogous state laws and regulations.
Removed
Proved reserves increased from 55.7 MMBoe at December 31, 2023 to 63.1 MMBoe at December 31, 2024, primarily due to purchases of 16.0 MMBoe, 3.5 MMBoe associated with other commercial improvements, and positive revisions of 2.3 MMBoe related to NGL Yield.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

63 edited+33 added−11 removed144 unchanged
Biggest changeRisk Factors Summary The following is a summary of the material risk factors that could adversely affect our business, financial condition, and results of operations: Risks Relating to the Oil and Natural Gas Industry and Our Business ◦ Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control ◦ Drilling for and producing oil and natural gas are high risk activities with many uncertainties ◦ Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production ◦ A financial downturn could negatively affect our business, results of operations, financial condition, cash flows and access to capital ◦ Future drilling activities face substantial uncertainties ◦ Certain of our undeveloped acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or we renew the leases ◦ We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and our ability to offset the natural decline in our oil, natural gas and NGL reserves ◦ Future commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties ◦ Significant inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves ◦ The loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations ◦ We are subject to litigation and adverse outcomes in such litigation could have a material effect on our financial condition ◦ The present value of future net cash flows from our proved reserves are not the same as the current market value of our estimated oil, natural gas and NGL reserves ◦ We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible ◦ Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather ◦ Our business could be affected by macroeconomic risks ◦ Capital market volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets ◦ Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them ◦ All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas ◦ Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured ◦ Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans ◦ Intense competition in the oil and natural gas industry may adversely affect our ability to succeed ◦ Seismic data may not accurately identify the presence of oil and natural gas, and the use of such technology requires greater predrilling expenditures ◦ Inflation may increase costs which can adversely impact cash flows and reserves value ◦ As we outsource functions, we are more dependent on the entities performing those functions.
Biggest changeFailure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth or offset the natural decline of our producing properties and adversely affect our results of operations. • Future drilling activities face substantial uncertainties • Certain of our undeveloped acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or we renew the leases • We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a loss of properties and our ability to offset the natural decline in our oil, natural gas and NGL reserves • Future commodity price declines may result in reductions of the asset carrying values of our oil and natural gas properties • Significant inaccuracies in our reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves • The loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations • We are subject to litigation and adverse outcomes in such litigation could have a material effect on our financial condition • The present value of future net cash flows from our proved reserves are not the same as the current market value of our estimated oil, natural gas and NGL reserves • We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible • Production of oil, natural gas and NGLs could be materially and adversely affected by natural disasters or severe weather • Our business could be affected by macroeconomic risks • Capital market volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets • Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them 24 Table of Contents • All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas • The inability of our significant customers to meet their obligations to us may adversely affect our financial results • Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured • Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans • Intense competition in the oil and natural gas industry may adversely affect our ability to succeed • Seismic data may not accurately identify the presence of oil and natural gas, and the use of such technology requires greater predrilling expenditures • Inflation may increase costs which can adversely impact cash flows and reserves value • As we outsource functions, we are more dependent on the entities performing those functions.
These anti-takeover provisions include: • lack of a provision for cumulative voting in the election of directors; • the ability of our Board to authorize the issuance of “blank check” preferred stock to increase the number of outstanding shares and thwart a takeover attempt; • advance notice requirements for nominations for election to the Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings; and • limitations on who may call a special meeting of stockholders.
These anti-takeover provisions include: • lack of a provision for cumulative voting in the election of directors; • the ability of the Board to authorize the issuance of “blank check” preferred stock to increase the number of outstanding shares and thwart a takeover attempt; • advance notice requirements for nominations for election to the Board or for proposing matters that can be acted upon by stockholders at stockholder meetings; and • limitations on who may call a special meeting of stockholders.
Failure to comply with these laws and regulations may result in litigation; the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory, remedial or corrective action obligations; the occurrence of delays or restrictions in permitting or performance of projects; and the issuance of orders and injunctions limiting or preventing some or all of our operations in affected areas. 34 Table of Contents Under certain environmental laws and regulations, we could be subject to strict, and/or joint and several liability for the investigation, removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken.
Failure to comply with these laws and regulations may result in litigation; the assessment of sanctions, including administrative, civil or criminal penalties; the imposition of investigatory, remedial or corrective action obligations; the occurrence of delays or restrictions in permitting or performance of projects; and the issuance of orders and injunctions limiting or preventing some or all of our operations in affected areas. 35 Table of Contents Under certain environmental laws and regulations, we could be subject to strict, and/or joint and several liability for the investigation, removal or remediation of previously released materials or property contamination, regardless of whether we were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken.
Additional impacts from cybersecurity incidents could include remediation costs, such as liability for stolen assets or information, repairs of system damage, and incentives to our business partners; increased cybersecurity protection costs, which may include the costs of making organizational changes, deploying additional personnel and security technologies, training employees, and engaging third-party experts and consultants; lost revenue resulting from the unauthorized use of proprietary information or the failure to retain or attract business partners following an attack; increased insurance premiums; and damage to the company’s competitiveness, stock price, and long-term shareholder value.
Additional impacts from cybersecurity incidents could include remediation costs, such as liability for stolen assets or information, repairs of system damage, and incentives to our business partners; increased cybersecurity protection costs, which may include the costs of making organizational changes, deploying additional personnel and security technologies, training employees, and engaging third-party experts and consultants; lost revenue resulting from the unauthorized use of proprietary information or the failure to retain or attract business partners following an attack; increased insurance premiums; and damage to the company’s competitiveness, stock price, and long-term stockholder value.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 20, 2023, the Company entered into an amendment to the Tax Benefits Preservation Plan, approved by shareholders, to extend the expiration time of the Tax Benefits Preservation Plan from July 1, 2023 to July 1, 2026.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 20, 2023, the Company entered into an amendment to the Tax Benefits Preservation Plan, approved by stockholders, to extend the expiration time of the Tax Benefits Preservation Plan from July 1, 2023 to July 1, 2026.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 20, 2023, the Company entered into an amendment to the Tax Benefits Preservation Plan, approved by shareholders, to extend the expiration time of the Tax Benefits Preservation Plan from July 1, 2023 to July 1, 2026.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 20, 2023, the Company entered into an amendment to the Tax Benefits Preservation Plan, approved by stockholders, to extend the expiration time of the Tax Benefits Preservation Plan from July 1, 2023 to July 1, 2026.
We maintained effective internal control over financial reporting as of December 31, 2024, as further described in Part II “Item 9A—Controls and Procedures” and “Management’s Report on Internal Control over Financial Reporting.” Our efforts to develop and maintain our internal controls and to remediate any material weaknesses in our controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.
We maintained effective internal control over financial reporting as of December 31, 2025, as further described in Part II “Item 9A—Controls and Procedures” and “Management’s Report on Internal Control over Financial Reporting.” Our efforts to develop and maintain our internal controls and to remediate any material weaknesses in our controls may not be successful, and we may be unable to maintain adequate controls over our financial processes and reporting in the future, including future compliance with the obligations under Section 404 of the Sarbanes-Oxley Act of 2002.
Because the Tax Benefits Preservation Plan could make it more expensive for a person to acquire a controlling interest in us, it could have the effect of delaying or preventing a change in control even if a change in control was in our stockholders’ interest. 39 Table of Contents Anti-takeover provisions in our charter documents and under Delaware corporate law may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders.
Because the Tax Benefits Preservation Plan could make it more expensive for a person to acquire a controlling interest in us, it could have the effect of delaying or preventing a change in control even if a change in control was in our stockholders’ interest. 40 Table of Contents Anti-takeover provisions in our charter documents and under Delaware corporate law may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders.
As of December 31, 2024, we had U.S. federal NOLs of $1.6 billion, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation, of which approximately $0.7 billion will expire between 2025 and 2037, if not limited by additional triggering events prior to such time.
As of December 31, 2025, we had U.S. federal NOLs of $1.6 billion, net of NOLs expected to expire unused due to the 2016 IRC Section 382 limitation, of which approximately $0.7 billion will expire between 2028 and 2037, if not limited by additional triggering events prior to such time.
We may outsource other functions in the future, which would increase our reliance on third parties. 33 Table of Contents We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
We may outsource other functions in the future, which would increase our reliance on third parties. 34 Table of Contents We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities.
Generally, an “ownership change” occurs if the percentage of the Company’s stock owned by one or more of its “five-percent shareholders” (as such term is defined in Section 382 of the IRC) increases by more than 50 percentage points over the lowest percentage of stock owned by such stockholder or stockholders at any time over a three-year period.
Generally, an “ownership change” occurs if the percentage of the Company’s stock owned by one or more of its “five-percent stockholders” (as such term is defined in Section 382 of the IRC) increases by more than 50 percentage points over the lowest percentage of stock owned by such stockholder or stockholders at any time over a three-year period.
These provisions may also discourage, delay or prevent a third party from acquiring a large portion of our securities, or initiating a tender offer, even if our stockholders might receive a premium for their shares in the acquisition over the then current market price. 40 Table of Contents
These provisions may also discourage, delay or prevent a third party from acquiring a large portion of our securities, or initiating a tender offer, even if our stockholders might receive a premium for their shares in the acquisition over the then current market price. 41 Table of Contents
The full cost ceiling is evaluated at the end of each quarter using the SEC prices, adjusted for the impact of derivatives accounted for as cash flow hedges, if any. The Company did not recognize any full cost ceiling impairment charges for the years ended December 31, 2024 or 2023.
The full cost ceiling is evaluated at the end of each quarter using the SEC prices, adjusted for the impact of derivatives accounted for as cash flow hedges, if any. The Company did not recognize any full cost ceiling impairment charges for the years ended December 31, 2025 or 2024.
The potential impact from infectious diseases is difficult to predict, and the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. 38 Table of Contents Risks Relating to Our NOLs Our ability to use our NOLs may be limited.
The potential impact from infectious diseases is difficult to predict, and the extent to which it may negatively affect our operating results or the duration of any potential business disruption is uncertain. 39 Table of Contents Risks Relating to Our NOLs Our ability to use our NOLs may be limited.
We cannot predict the timing or scale of these various macroeconomic conditions, but they could have a material adverse affect on our business, results of operations and financial condition. 31 Table of Contents The capital markets could be volatile, and such volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets.
We cannot predict the timing or scale of these various macroeconomic conditions, but they could have a material adverse affect on our business, results of operations and financial condition. The capital markets could be volatile, and such volatility could adversely affect our ability to obtain capital, cause us to incur additional financing expense or affect the value of certain assets.
While we maintain insurance coverage that we deem appropriate for these risks, our operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. 32 Table of Contents Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans on a timely basis and within our budget.
While we maintain insurance coverage that we deem appropriate for these risks, our operations may result in liabilities exceeding such insurance coverage or liabilities not covered by insurance. Shortages or increases in costs of equipment, services and qualified personnel could adversely affect our ability to execute our development plans on a timely basis and within our budget.
The Company's Board of Directors (the "Board") adopted the Tax Benefits Preservation Plan in an effort to protect stockholder value by attempting to protect against a possible limitation on our ability to use our NOLs. We may utilize these NOLs in certain circumstances to offset future United States taxable income and reduce our United States federal income tax liability.
The Board adopted the Tax Benefits Preservation Plan in an effort to protect stockholder value by attempting to protect against a possible limitation on our ability to use our NOLs. We may utilize these NOLs in certain circumstances to offset future United States taxable income and reduce our United States federal income tax liability.
Actual future net cash flows from our oil and natural gas properties will be affected by actual prices we receive for oil, natural gas and NGLs, as well as other factors such as: • the actual cost of development and production expenditures; • the amount and timing of actual production; • supply of and demand for oil, natural gas and NGLs; and • changes in governmental regulation or taxation.
Actual future net cash flows from our oil and natural gas properties will be affected by actual prices we receive for oil, natural gas and NGLs to include derivative instruments, as well as other factors such as: • the actual cost of development and production expenditures; • the amount and timing of actual production; • supply of and demand for oil, natural gas and NGLs; and • changes in governmental regulation or taxation.
We are, and from time to time may become, subject to litigation and various legal proceedings, including stockholder derivative suits, class action lawsuits and other matters, that involve claims for substantial amounts of money or for other relief or that might necessitate changes to our business or operations. Refer to Item 3.
We are, and from time to time may become, subject to litigation and various legal proceedings, including stockholder derivative suits, class action lawsuits and other matters, that involve claims for substantial amounts of money or for other relief or that might necessitate changes to our business or operations. Refer to Item 3. “Legal Proceedings” for additional information.
In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including among others the following: • reductions in oil, natural gas and NGL prices; • delays imposed by or resulting from compliance with regulatory requirements including permitting; • unusual or unexpected geological formations and miscalculations; • shortages of or delays in obtaining equipment and qualified personnel; • shortages of or delays in obtaining water and sand for hydraulic fracturing operations; • equipment malfunctions, failures or accidents; • lack of available gathering or midstream facilities or delays in construction of gathering or midstream facilities; • lack of available capacity on interconnecting transmission pipelines; • lack of adequate electrical infrastructure and water disposal capacity; • unexpected operational events and drilling conditions; • pipe or cement failures and casing collapses; • pressures, fires, blowouts and explosions; • lost or damaged drilling and service tools; • loss of drilling fluid circulation; • uncontrollable flows of oil, natural gas, brine, water or drilling fluids; • natural disasters; • environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment; • high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing; • Offset activity by other operators could delay our operations or adversely affect results; 27 Table of Contents • compliance with environmental and other governmental requirements; • adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes; • oil and natural gas property title problems; • market and midstream limitations for oil, natural gas and NGLs; • unexpected subsurface conditions; • lack of qualified labor; • lack of hydrocarbon content; and • low pressure, depletion from existing wells, parent / child effect, or other conditions that may reduce ultimate recovery of reserves.
In addition, our drilling and producing operations may be curtailed, delayed or canceled as a result of various factors, including among others the following: • reductions in oil, natural gas and NGL prices; • delays imposed by or resulting from compliance with regulatory requirements including permitting; • unusual or unexpected geological formations and miscalculations; • shortages of or delays in obtaining equipment and qualified personnel; • shortages of or delays in obtaining water and sand for hydraulic fracturing operations; • equipment malfunctions, failures or accidents; • lack of available gathering or midstream facilities or delays in construction of gathering or midstream facilities; • lack of available capacity on interconnecting transmission pipelines; • lack of adequate electrical infrastructure and water disposal capacity; • unexpected operational events and drilling conditions; • pipe or cement failures and casing collapses; • pressures, fires, blowouts and explosions; • lost or damaged drilling and service tools; • loss of drilling fluid circulation; • uncontrollable flows of oil, natural gas, brine, water or drilling fluids; • natural disasters; • environmental hazards, such as oil spills and natural gas leaks, pipeline or tank ruptures, encountering naturally occurring radioactive materials and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment; • high costs, shortages or delivery delays of equipment, labor or other services, or water used in hydraulic fracturing; • Offset activity by other operators could delay our operations or adversely affect results; • compliance with environmental and other governmental requirements; • adverse weather conditions such as extreme cold, fires caused by extreme heat or lack of rain, and severe storms, tornadoes or hurricanes; • oil and natural gas property title problems; • market and midstream limitations for oil, natural gas and NGLs; • unexpected subsurface conditions; • lack of qualified labor; • lack of hydrocarbon content; and • low pressure, depletion from existing wells, parent / child effect, or other conditions that may reduce ultimate recovery of reserves. 27 Table of Contents Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.
These factors include, among others: • changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally; ◦ the timing of planned United States' liquefied natural gas projects, data storage, electrification and other factors will impact demand for natural gas; • the price and quantity of foreign imports; • the amount of exports from the U.S.; • U.S. and worldwide political and economic conditions, including armed conflict and related sanctions; • the level of global and U.S. inventories and reserves; • weather conditions and seasonal trends; • anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities; • technological advances affecting energy consumption and energy supply; • the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity; • natural disasters and other extraordinary events; • domestic and foreign governmental regulations and taxation; 26 Table of Contents • energy conservation and environmental measures; • the price and availability of alternative fuels and energy sources; • the strength or weakness of the U.S. dollar to other currencies; • inflation and ability to acquire critical material, equipment or services in a timely or cost effective manner; and • availability of capital or level of hedging across the energy industry in the U.S. and internationally.
These factors include, among others: • changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGLs, as well as perceptions of supply of, and demand for, oil, natural gas and NGLs generally; • the timing of planned United States' liquefied natural gas projects, data storage, electrification and other factors will impact demand for natural gas; • the price and quantity of foreign imports; • the amount of exports from the U.S.; • U.S. and worldwide political and economic conditions, including armed conflict and related sanctions including, but not limited to, the conflicts in the Middle East, Ukraine and Iran, and political instability in Venezuela; • the level of global and U.S. inventories and reserves; • weather conditions and seasonal trends; • anticipated future prices of oil, natural gas and NGLs, alternative fuels and other commodities; • technological advances affecting energy consumption and energy supply; • the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity; • natural disasters and other extraordinary events; • domestic and foreign governmental regulations and taxation; • energy conservation and environmental measures; • the price and availability of alternative fuels and energy sources; • the strength or weakness of the U.S. dollar to other currencies; • inflation and ability to acquire critical material, equipment or services in a timely or cost effective manner; and • availability of capital or level of hedging across the energy industry in the U.S. and internationally.
On July 1, 2020, our Board of Directors approved, and the Company adopted, as amended on March 16, 2021, a Tax Benefits Preservation Plan in order to protect shareholder value against a possible limitation on the Company’s ability to use its tax NOLs and certain other tax benefits to reduce potential future U.S. federal income tax obligations.
On July 1, 2020, the Board approved, and the Company adopted, as amended on March 16, 2021, a Tax Benefits Preservation Plan in order to protect stockholder value against a possible limitation on the Company’s ability to use its tax NOLs and certain other tax benefits to reduce potential future U.S. federal income tax obligations.
Cumulative full cost ceiling impairment from the Emergence Date through December 31, 2024 totaled $947.1 million.
Cumulative full cost ceiling impairment from the Emergence Date through December 31, 2025 totaled $947.1 million.
In addition, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa. However, the EPA has taken several steps to delay implementation of the Quad Oa standards.
In addition, in June 2016, the EPA finalized rules to reduce methane emissions from new, modified or reconstructed sources in the oil and natural gas sector, including implementation of an LDAR program to minimize methane emissions, under the CAA’s New Source Performance Standards Quad Oa.
However, there is no assurance that the Tax Benefits Preservation Plan will prevent all transfers that could result in such an “ownership change.” The value of our NOLs and certain other tax benefits is also dependent upon the tax rates expected to be in effect at the time the taxable income is expected to be generated.
There is no assurance that the Tax Benefits Preservation Plan will prevent an “ownership change.” The value of our NOLs and certain other tax benefits is also dependent upon the tax rates expected to be in effect at the time the taxable income is expected to be generated.
For natural gas, from January 2020 through December 2024, the NYMEX Henry Hub spot prices fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf.
For natural gas, from January 1, 2021 through December 31, 2025, the NYMEX Henry Hub spot prices fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf.
Disruptions or delays at our third-party service providers could adversely impact our operations ◦ Complex laws and regulations could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities ◦ Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines 25 Table of Contents ◦ Our operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations ◦ Legislative or regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production ◦ Legislative or regulatory initiatives relating to seismic activity could limit our ability to produce oil and natural gas economically ◦ Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce ◦ Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results ◦ Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business ◦ Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations ◦ Repercussions from terrorist activities or armed conflict could harm our business ◦ Conservation measures and technological advances could reduce demand for oil and natural gas ◦ Events outside of our control, including an epidemic or outbreak of an infectious disease, may materially adversely affect our business Risks Relating to our NOLs ◦ Our ability to use our NOLs may be limited, and our Tax Benefits Preservation Plan may not prevent an ownership change resulting in loss of the Company’s NOLs Risks Relating to our Common Stock ◦ We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover ◦ Anti-takeover provisions in our charter documents may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders For a more complete discussion of the material risk factors relevant to us, see below.
Disruptions or delays at our third-party service providers could adversely impact our operations • Complex laws and regulations could adversely affect the cost, manner or feasibility of conducting our operations or expose us to significant liabilities • Should we fail to comply with all applicable statutes, rules, regulations and orders of the FERC, the CFTC, the FTC or other regulators, we could be subject to substantial penalties and fines • Our operations are subject to environmental and occupational safety and health laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations • Legislative or regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays and adversely affect our production • Legislative or regulatory initiatives relating to seismic activity could limit our ability to produce oil and natural gas economically • Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce • Our failure to maintain an adequate system of internal control over financial reporting could adversely affect our ability to accurately report our results • Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business • Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations • Conservation measures and technological advances could reduce demand for oil and natural gas Risks Relating to our NOLs • Our ability to use our NOLs may be limited, and our Tax Benefits Preservation Plan may not prevent an ownership change resulting in loss of the Company’s NOLs Risks Relating to our Common Stock • We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover • Anti-takeover provisions in our charter documents may make it more difficult to acquire us, even though such acquisitions may be beneficial to our stockholders • There is no guarantee of future dividends or stock repurchases.
Business—Developed and Undeveloped Acreage.” Our development operations or ability to acquire oil and gas properties and reserves require substantial capital.
Business—Developed and Undeveloped Acreage.” 29 Table of Contents Our development operations or ability to acquire oil and gas properties and reserves require substantial capital.
“Legal Proceedings” for additional information. 30 Table of Contents The present value of future net cash flows from our proved reserves calculated in accordance with SEC guidelines are not the same as the current market value of our estimated oil, natural gas and NGL reserves.
The present value of future net cash flows from our proved reserves calculated in accordance with SEC guidelines are not the same as the current market value of our estimated oil, natural gas and NGL reserves.
For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued CAA final regulations in 2012 and additional CAA regulations in June 2016 governing performance standards for the oil and natural gas industry; and in June 2016 issued final effluent limitations guidelines under the CWA that waste-water from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant.
For example, the EPA published permitting guidance in February 2014 addressing the use of diesel fuel in fracturing operations; issued the Quad Oa regulations for the oil and natural gas industry under CAA, as described above; and in June 2016 issued final effluent limitations guidelines under the CWA that wastewater from shale natural gas extraction operations must meet before discharging to a publicly-owned treatment plant.
As of December 31, 2024, we held 371,748 total net acres (including developed and undeveloped net acres), of which 37,269 net acres is undeveloped. Of our net undeveloped acreage, 43% are subject to expiration at the end of their primary terms. For additional information on our developed and undeveloped acreage please see the section “Item 1.
As of December 31, 2025, we held 378,537 total net acres (including developed and undeveloped net acres), of which 40,914 net acres is undeveloped. Of our net undeveloped acreage, 40% are subject to expiration at the end of their primary terms. For additional information on our developed and undeveloped acreage please see the section “Item 1.
If events of this nature occur and persist, the attendant political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues.
If events of this nature occur and persist, the attendant political instability and societal disruption, including, but not limited to, the conflicts in the Middle East, Ukraine and Iran, and political instability in Venezuela, could reduce overall demand for oil and natural gas, potentially putting downward pressure on prevailing oil and natural gas prices and causing a reduction in our revenues.
As a result, such tariffs could materially and adversely affect our business, financial condition, results of operations, and cash flows. Future drilling activities face substantial uncertainties.
As a result, such tariffs could materially and adversely affect our business, financial condition, results of operations, and cash flows.
In particular, cash flow from operations were $73.9 million and $115.6 million for the years ended December 31, 2024 and 2023, respectively.
In particular, cash flow from operations were $100.1 million and $73.9 million for the years ended December 31, 2025 and 2024, respectively.
Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of our internal controls could harm our operating results.
Any failure to develop or maintain effective controls, or difficulties encountered in their implementation, including those related to acquired businesses, or other effective improvement of our internal controls could harm our operating results. Ineffective internal controls could also cause investors to lose confidence in our reported financial information.
For oil, from January 2020 through December 2024, the NYMEX West Texas Intermediate ("WTI") settled price fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl.
For oil, from January 1, 2021 through December 31, 2025, the NYMEX West Texas Intermediate ("WTI") settled price fluctuated between a high of $123.64 per Bbl and a low of $47.47 per Bbl.
The Dodd-Frank Act also established a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes).
The Dodd-Frank Act also established a new Energy and Environmental Markets Advisory Committee to make recommendations to the CFTC regarding matters of concern to exchanges, firms, end users and regulators with respect to energy and environmental markets and also expands the CFTC’s power to impose position limits on specific categories of swaps (excluding swaps entered into for bona fide hedging purposes). 37 Table of Contents There are some exceptions to these requirements for entities that use swaps to hedge or mitigate commercial risk.
The failure to obtain additional financing could result in a curtailment of our operations relating to development of prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGL reserves. 29 Table of Contents Future price declines may result in reductions of the asset carrying values of our oil and natural gas properties.
The failure to obtain additional financing could result in a curtailment of our operations relating to development of prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGL reserves.
We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.
Under this accounting method, all costs for both productive and nonproductive properties are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method.
For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations.
Based on its Endangerment Findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA. For example, the EPA has adopted rules requiring the reporting of GHG emissions from various oil and natural gas operations on an annual basis, which includes certain of our operations.
We undertake ongoing improvements to our systems, connected devices and information-sharing products in order to minimize vulnerabilities, in accordance with industry and regulatory standards; however, because the techniques used to obtain unauthorized access change frequently and can be difficult to detect, anticipating, identifying or preventing these intrusions or mitigating them if and when they occur is challenging and makes us vulnerable.
We undertake ongoing improvements to our systems, connected devices and information-sharing products in order to minimize vulnerabilities, in accordance with industry and regulatory standards; however, because the techniques used to obtain unauthorized access change frequently and can be difficult to detect, anticipating, identifying or preventing these intrusions or mitigating them if and when they occur is challenging and makes us vulnerable. 38 Table of Contents If our security measures are circumvented, proprietary information may be misappropriated, our operations may be disrupted, and our computers or those of our customers or other third parties may be damaged.
In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season. For NGLs, prices exhibited similar volatility from January 2020 through December 2024.
In addition, the market price of natural gas is generally higher in the winter months than during other months of the year due to increased demand for natural gas for heating purposes during the winter season.
If financial institutions that extended credit commitments to us are adversely affected by volatile conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments to us, which could have a material adverse effect on our financial condition and ability to borrow funds, if needed, for working capital, capital expenditures and other corporate purposes.
If financial institutions that extended credit commitments to us are adversely affected by volatile conditions of the U.S. and international capital markets, they may become unable to fund borrowings under their credit commitments to us, which could have a material adverse effect on our financial condition and ability to borrow funds, if needed, for working capital, capital expenditures and other corporate purposes. 32 Table of Contents Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them.
The EPA previously published its findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes. Based on these findings, the EPA has adopted various rules to address GHG emissions under existing provisions of the CAA.
The EPA previously published its Endangerment Findings that emissions of GHGs present a danger to public health and the environment because such gases are, according to the EPA, contributing to warming of the Earth’s atmosphere and other climatic changes, which the EPA has proposed rescinding.
Many of these companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis.
The oil and natural gas industry is intensely competitive, and we compete with many companies that have greater financial and other resources than we do. Many of these companies not only explore for and produce oil and natural gas, but also conduct refining operations and market petroleum and other products on a regional, national or worldwide basis.
All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas. With the divestment of our North Park Basin assets in February 2021, all of our production and reserves are located in the Mid-Continent region.
All of our operations are located in the Mid-Continent region, making us vulnerable to risks associated with operating in a limited number of major geographic areas. All of our production and reserves are located in the Mid-Continent region. This concentration could disproportionately expose us to operational and regulatory risk in this area.
We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible. The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive or may suffer from declining production faster than anticipated.
The cost of drilling, completing and operating any well is often uncertain, and new wells may not be productive or may suffer from declining production faster than anticipated.
Refer to “—Environmental Regulations— Subsurface Injections” included in Item 1 of this report for additional discussion of the current and potential impacts of legislation or regulatory initiatives related to seismic activity on our operations.
Refer to “—Environmental Regulations— Subsurface Injections” included in Item 1 of this report for additional discussion of the current and potential impacts of legislation or regulatory initiatives related to seismic activity on our operations. 36 Table of Contents Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities. 35 Table of Contents Evaluation of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities occur or are proposed to be performed.
While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.
The EPA also issued an Advance Notice of Proposed Rulemaking under TSCA in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing, but, to date, has taken no further action. Separately, the BLM published a final rule in March 2015 that establishes more stringent standards for performing hydraulic fracturing on federal and Indian lands.
The EPA also issued an Advance Notice of Proposed Rulemaking under TSCA in 2014 regarding reporting of the chemical substances and mixtures used in hydraulic fracturing, but, to date, has taken no further action. From time to time, the U.S.
Our revenues, profitability and cash flow are highly dependent upon the prices we realize from the sale of oil, natural gas and NGLs. Historically, the markets for these commodities are very volatile. Prices for oil, natural gas and NGLs can move quickly and fluctuate widely in response to a variety of factors that are beyond our control.
Prices for oil, natural gas and NGLs can move quickly and fluctuate widely in response to a variety of factors that are beyond our control.
We have entered and may enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas, and NGL price volatility.
Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business. We have entered and may enter into financial derivative instruments with respect to a portion of our production to manage our exposure to oil, gas, and NGL price volatility.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit.
Drilling for oil and natural gas can be unprofitable if dry wells are drilled and if productive wells do not produce sufficient revenues to return a profit.
Because of these uncertain factors, we do not know if certain locations will ever be drilled or if we will be able to produce natural gas or oil from any of our potential locations. 28 Table of Contents Certain of our undeveloped acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage or we renew the leases.
Because of these uncertain factors, we do not know if certain locations will ever be drilled or if we will be able to produce natural gas or oil from any of our potential locations.
Cybersecurity incidents or security breaches also could result in litigation and legal risks, including regulatory actions by state, federal, and non-US governmental authorities, as well as significant additional expense to implement further data protection measures. 37 Table of Contents In addition to the risks presented to our systems and networks, cybersecurity incidents affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets.
Cybersecurity incidents or security breaches also could result in litigation and legal risks, including regulatory actions by state, federal, and non-US governmental authorities, as well as significant additional expense to implement further data protection measures.
Additionally, higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could significantly affect our ability to execute our development plans as projected.
Additionally, higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services.
Properties we acquire may not produce as projected, and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against them. Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible.
Our initial technical reviews of properties we acquire are necessarily limited because an in-depth review of every individual property involved in each acquisition generally is not feasible.
Risks Relating to the Oil and Natural Gas Industry and Our Business Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control. Declines in oil, natural gas or NGL prices significantly affect our financial condition and results of operations.
For a more complete discussion of the material risk factors relevant to us, see below. 25 Table of Contents Risks Relating to the Oil and Natural Gas Industry and Our Business Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control.
On November 8, 2022, EPA issued a supplemental notice of proposed rulemaking that would impose standards for certain sources that were not addressed in the November 2021 proposal, revise the previously proposed emissions standards, and establish a “super emitter response program” allowing local regulatory agencies and EPA-certified third parties to issue notices to owners and operators of regulated facilities when they detect a so-called “super-emitting event.” Additionally, as discussed above in the description of our business, various regulatory bodies have announced or are considering new rules and regulations impacting our operations and our business, including the EPA’s final rule under the CAA to reduce methane emissions from the oil and natural gas industry, EPA and BLM methane emissions limitations, cap and trade programs launched by states and regions in which we operate, and, to the extent applicable, the Paris Agreement.
Additionally, as discussed above in the description of our business, various regulatory bodies have announced or are considering new rules and regulations impacting our operations and our business, including the EPA’s final rule under the CAA to reduce methane emissions from the oil and natural gas industry under Subparts OOOOb/c, EPA and BLM methane emissions limitations, cap and trade programs launched by states and regions in which we operate, and, to the extent applicable, the Paris Agreement.
Our current estimates of reserves could change, potentially in material amounts, in the future.
Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves. Our current estimates of reserves could change, potentially in material amounts, in the future.
These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified. Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured.
These factors could have a significantly greater impact on our financial condition, results of operations and cash flows than if our properties were more diversified. The inability of our significant customers to meet their obligations to us may adversely affect our financial results.
In addition, we use a 10% discount factor when calculating discounted future net cash flows, which may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.
In addition, the 10% discount factor we use when calculating discounted future net cash flow requirements in compliance with ASC 932, “Extractive Activities — Oil and Gas,” may not be the most appropriate based on prevailing interest rate, market, risks or other factors. 31 Table of Contents We will not know conclusively prior to drilling whether oil or natural gas will be present in sufficient quantities to be economically producible.
Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed. The oil and natural gas industry is intensely competitive, and we compete with many companies that have greater financial and other resources than we do.
Shortages of field personnel and equipment or price increases could significantly affect our ability to execute our development plans as projected. 33 Table of Contents Competition in the oil and natural gas industry is intense, which may adversely affect our ability to succeed.
Removed
Certain of these risks can cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, environmental contamination or loss of wells and regulatory fines or penalties.
Added
Risk Factors Summary The following is a summary of the material risk factors that could adversely affect our business, financial condition, and results of operations: Risks Relating to the Oil and Natural Gas Industry and Our Business • Oil, natural gas and NGL prices fluctuate widely due to a number of factors that are beyond our control • Drilling for and producing oil and natural gas are high risk activities with many uncertainties • Market conditions or operational impediments may hinder our access to oil, natural gas and NGL markets or delay production • A financial downturn could negatively affect our business, results of operations, financial condition, cash flows and access to capital • Our producing properties are depleting assets, and the development or acquisition of additional reserves would be necessary to maintain or increase our production levels as the natural decline of our producing assets would result in a decrease in production levels.
Removed
The amount of such future write-downs and non-cash charges could be substantial. Our estimated reserves are based on many assumptions that may turn out to be different. Any significant inaccuracies in these reserve estimates or underlying assumptions could materially affect the quantities and present value of our reserves.
Added
The declaration of dividends and repurchases of our common stock are at the discretion of our Board of Directors, based on relevant considerations, with no assurance of future payments or repurchases at levels anticipated by stockholders.
Removed
This concentration could disproportionately expose us to operational and regulatory risk in this area.
Added
Declines in oil, natural gas or NGL prices significantly affect our financial condition and results of operations. Our revenues, profitability and cash flow are highly dependent upon the prices we realize from the sale of oil, natural gas and NGLs. Historically, the markets for these commodities are very volatile.
Removed
However, the U.S. District Court of Wyoming struck down this rule in June 2016, and after various appeals and a presidential executive order directing it to review rules related to the energy industry, the BLM published a final rule rescinding the 2015 rule in December 2017. From time to time, the U.S.
Added
For NGLs, prices exhibited similar volatility from January 1, 2021 through December 31, 2025. 26 Table of Contents Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations.
Removed
Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
Added
Failure to successfully identify, complete and integrate acquisitions of properties or business combinations, or the lack of development activity, could slow or even eliminate our growth due to the natural decline of our producing properties and adversely affect our results of operations.
Removed
The agency proposed a rulemaking in June 2017 to stay the requirements for a period of two years and in October 2018, the EPA proposed revisions to Quad Oa, such as changes to the frequency for monitoring fugitive emissions at well sites and changes to requirements that a professional engineer certify when meeting certain Quad Oa requirements is technically infeasible.
Added
Our future success depends on the development or acquisition of additional oil, natural gas and NGL reserves that are economically recoverable, as our proved reserves will generally decline as reserves are depleted. To increase reserves and production, we would need to undertake replacement activities to undertake development, exploration and other replacement activities, requiring substantial capital expenditures.
Removed
In September 2020, the EPA finalized amendments to Quad Oa that rescind requirements for the transmission and storage segment of the oil and natural gas industry and rescind methane-specific limits that apply to the industry’s production and processing segments, among other things.
Added
Such activities may not result in significant additional reserves and efforts to drill productive wells at low finding costs may be unsuccessful. The successful acquisition of businesses and producing properties requires an assessment of several factors, including; recoverable reserves, future oil and natural gas prices and their applicable differentials, operating costs and potential environmental and other liabilities.
Removed
On June 30, 2021, Congress issued a joint resolution pursuant to the Congressional Review Act disapproving the September 2020 rule, and on November 15, 2021, EPA issued a proposed rule to revise the Quad Oa regulations.
Added
The accuracy of these assessments is inherently uncertain and we may not be able to identify attractive acquisition opportunities. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices.
Removed
Ineffective internal controls could also cause investors to lose confidence in our reported financial information. 36 Table of Contents Our derivative activities could result in financial losses and are subject to new derivatives legislation and regulation, which could adversely affect our ability to hedge risks associated with our business.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeAny cybersecurity incident could have a material adverse effect on our reputation, competitive position, business, financial condition and results of operations. 41 Table of Contents Additionally, although out of our control, cybersecurity incidents affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets, which could, in turn, have a material adverse effect on our business, financial condition and results of operations.
Biggest changeAdditionally, although out of our control, cybersecurity incidents affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery of our production to markets, which could, in turn, have a material adverse effect on our business, financial condition and results of operations.
Item 1C. Cybersecurity Risk Management and Strategy As SandRidge has increasingly relied on information technology systems and networks in connection with our business activities, we recognize the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data.
Item 1C. Cybersecurity Risk Management and Strategy As SandRidge has increasingly relied on information technology ("IT") systems and networks in connection with our business activities, we recognize the critical importance of developing, implementing, and maintaining robust cybersecurity measures to safeguard our information systems and protect the confidentiality, integrity, and availability of our data.
Risk Factors—Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations .” Governance – Board Oversight and the Role of Management The Board of Directors is acutely aware of the critical nature of managing risks associated with cybersecurity threats.
Risk Factors—Cybersecurity incidents or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of our business operations .” Governance – Board Oversight and the Role of Management The Board is acutely aware of the critical nature of managing risks associated with cybersecurity threats.
Furthermore, significant cybersecurity matters, and strategic risk management decisions are escalated to the Board of Directors, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
Furthermore, significant cybersecurity matters, and strategic risk management decisions are escalated to the Board, ensuring that they have comprehensive oversight and can provide guidance on critical cybersecurity issues.
The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for SOX, and cybersecurity breach protocols, policies and assessments.
The Director of Internal Audit is a Certified Fraud Examiner with over 20 years of planning and managing information technology audits, including information technology general controls for the Sarbanes-Oxley Act ("SOX"), and cybersecurity breach protocols, policies and assessments.
Although such prior incidents have not had a material adverse impact on our operations or financial performance, there can be no assurance that we will be successful in preventing cybersecurity incidents or successfully mitigating their effect on our Company.
Although such prior incidents have not had a material adverse impact on our operations or financial performance, there can be no assurance that we will be successful in preventing cybersecurity incidents or successfully mitigating their effect on our Company. Any cybersecurity incident could have a material adverse effect on our reputation, competitive position, business, financial condition and results of operations.
We conduct thorough security assessments of all third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. The monitoring includes assessments by our internal audit and IT professionals. This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties.
We conduct thorough security assessments of all third-party providers before engagement and maintain ongoing monitoring to ensure compliance with our cybersecurity standards. The monitoring includes assessments by our internal audit and IT professionals.
Incidents and Threats We have in the past experienced, and expect to continue to confront, cybersecurity incidents and cybersecurity threats from hackers and other third parties.
This approach is designed to mitigate risks related to data breaches or other security incidents originating from third parties. 42 Table of Contents Incidents and Threats We have in the past experienced, and expect to continue to confront, cybersecurity incidents and cybersecurity threats from hackers and other third parties.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+1 added−2 removed1 unchanged
Biggest changeDividend payments for the year ended December 31, 2024 totaled $72.3 million, which included $0.5 million of dividends on vested stock awards. See Note 19 for discussion on dividends declared paid in 2025. The payment of any dividends in the future, and the timing and amount thereof, is within the discretion of our Board of Directors.
Biggest changeDividends Dividend payments, excluding shares issued in lieu of cash dividends, for the year ended December 31, 2025 totaled $15.9 million, which included $0.2 million of dividends on vested stock awards. See Note 19 for discussion on dividends declared paid in 2026.
Shares withheld are initially recorded as treasury shares, then immediately retired. (2) In May 2023, the Company's Board of Directors approved the initiation of a share repurchase program authorizing the Company to purchase up to an aggregate of $75.0 million of the Company’s common stock.
Shares withheld are initially recorded as treasury shares, then immediately retired. (2) In May 2023, the Board approved the initiation of a share repurchase program authorizing the Company to purchase up to an aggregate of $75.0 million of the Company’s common stock.
Our Board of Directors' decisions regarding the payment of dividends will depend on many factors, such as our financial condition, earnings, capital requirements, debt service obligations, restrictive covenants in our debt, industry practice, legal requirements, regulatory constraints, and other factors that our Board of Directors deems relevant.
The Boards' decisions regarding the payment of dividends will depend on many factors, such as our financial condition, earnings, capital requirements, debt service obligations, restrictive covenants in our debt, industry practice, legal requirements, regulatory constraints, and other factors that the Board deems relevant.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Market Information Since October 4, 2016, the Company’s common stock has been listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” 42 Table of Contents Holders On March 4, 2025, there were 309 record holders of the Company’s common stock, which does not reflect persons or entities that hold the common stock in nominee or “street” name through various brokerage firms and financial institutions.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 43 Table of Contents Market Information Since October 4, 2016, the Company’s common stock has been listed on the New York Stock Exchange (“NYSE”) under the symbol “SD.” Holders As of February 26, 2026, there were 307 record holders of the Company’s common stock, which does not reflect persons or entities that hold the common stock in nominee or “street” name through various brokerage firms and financial institutions.
Issuer Purchases of Equity Securities Period Total Number of Shares Purchased(1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program(2) Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)(2) October 1, 2024 - October 31, 2024 — $ — — $ 75.0 November 1, 2024 - November 30, 2024 3,248 $ 11.64 — $ 75.0 December 1, 2024 - December 31, 2024 — $ 10.94 21,308 $ 74.8 Total 3,248 21,308 (1) Includes shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards.
Issuer Purchases of Equity Securities Period Total Number of Shares Purchased(1) Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Program(2) Maximum Approximate Dollar Value of Shares that May Yet Be Purchased Under the Program (in Millions)(2) October 1, 2025 - October 31, 2025 — $ — — $ 68.3 November 1, 2025 - November 30, 2025 3,248 $ 14.43 — $ 68.3 December 1, 2025 - December 31, 2025 — $ — — $ 68.3 Total 3,248 — (1) Includes 3,248 shares of common stock tendered by employees in order to satisfy tax withholding requirements upon vesting of their stock awards.
The maximum number of shares that may still be purchased under the buyback program as of March 4, 2025 is approximately 6.7 million.
The maximum number of shares that may still be purchased under the buyback program is approximately 4.0 million as of February 26, 2026.
Removed
Dividends In January 2024, the Board approved a one-time cash dividend of $1.50 per share of the Company's common stock, which was paid on February 20, 2024 to shareholders of record as of the close of business on February 5, 2024. The aggregate total payout was approximately $55.6 million.
Added
The payment of any dividends in the future, and the timing and amount thereof, is within the discretion of the Board.
Removed
Additionally, in March 2024, the Board increased the on-going quarterly dividend to $0.11 per share which was paid in March, May, August, and November 2024. The aggregate total payout was $16.3 million. Dividend payments are subject to quarterly approval by the Board as discussed below.

Item 7. Management's Discussion & Analysis

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

43 edited+8 added−21 removed34 unchanged
Biggest changeProduction in 2024 decreased slightly due to the natural decline of our producing assets, but benefited by our newly acquired wells beginning in September 2024, as well as periods of ethane recovery. 44 Table of Contents Total production by volume on a Boe basis for the years ended December 31, 2024 and 2023 was composed of the following: Year Ended December 31, 2024 2023 Oil 15.2 % 17.0 % Natural gas 53.6 % 55.3 % NGL 31.2 % 27.7 % Total 100.0 % 100.0 % Highlighted Events • On August 30, 2024, the Company closed on its previously announced acquisition of certain producing oil and natural gas properties in the Cherokee Play of the Western Anadarko Basin for $121.9 million, after customary post-closing adjustments.
Biggest changeThe charts below show production and percent revenues by product for the years ended December 31, 2025 and 2024: 45 Table of Contents Total production by volume on a Boe basis was composed of the following: Year Ended December 31, 2025 2024 Oil 17.9 % 15.2 % Natural gas 48.8 % 53.6 % NGL 33.3 % 31.2 % Total 100.0 % 100.0 % Highlighted Events • On August 5, 2025, the Board approved a dividend reinvestment plan (the “Dividend Reinvestment Plan”), pursuant to which the shareholders of the Company may, at their election, reinvest any dividends declared by the Board.
We have applied the Securities and Exchange Commission’s adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent calendar years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended December 31, 2024 and 2023.
We have applied the Securities and Exchange Commission’s adopted FAST Act Modernization and Simplification of Regulation S-K, which limits the discussion to the two most recent calendar years. This discussion and analysis deals with comparisons of material changes in the consolidated financial statements for years ended December 31, 2025 and 2024.
Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2024 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2025.
Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2025 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 2026.
As of December 31, 2024, we had future contractual commitments under various agreements, which are summarized below. The short-term leases are not recorded in the accompanying consolidated balance sheets.
As of December 31, 2025, we had future contractual commitments under various agreements, which are summarized below. The short-term leases are not recorded in the accompanying consolidated balance sheets.
For the comparison of the years ended December 31, 2023 and 2022, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2023 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 7, 2024.
For the comparison of the years ended December 31, 2024 and 2023, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2024 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 11, 2025.
During the year ended December 31, 2024, plugging and abandonment costs incurred were $0.9 million. 53 Table of Contents Critical Accounting Estimates The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.
During the year ended December 31, 2025, plugging and abandonment costs incurred were $1.0 million. 53 Table of Contents Critical Accounting Estimates The discussion and analysis of the Company’s financial condition and results of operations are based upon the Company’s consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America.
The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies. Proved Reserves. Approximately 97.5% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2024.
The Company’s critical accounting policies and additional information on significant estimates are discussed below. See “Note 1—Summary of Significant Accounting Policies” to the Company’s accompanying consolidated financial statements in Item 8 of this report for additional discussion of significant accounting policies. Proved Reserves. Approximately 97.9% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2025.
To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below: Year Ended December 31, 2024 2023 NYMEX WTI Oil (per Bbl) $ 76.63 $ 77.58 NYMEX Henry Hub Natural gas (per Mcf) $ 2.27 $ 2.63 In order to reduce our exposure to price fluctuations, from time to time we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A.
To provide information on the general trend in pricing, the average annual NYMEX prices for oil and natural gas for recent years are presented in the table below: Year Ended December 31, 2025 2024 NYMEX WTI Oil (per Bbl) $ 65.39 $ 76.63 NYMEX Henry Hub Natural gas (per Mcf) $ 3.65 $ 2.27 In order to reduce our exposure to price fluctuations, from time to time we enter into commodity derivative contracts for a portion of our anticipated future oil, natural gas, and NGL production as discussed in Item 7A.
When excluding the effects of pricing and other commercial assumptions, the Company revised its proved reserves an average of approximately 5% over the past five years and the revisions for the year ended December 31, 2024 were approximately 3%.
When excluding the effects of pricing and other commercial assumptions, the Company revised its proved reserves an average of approximately 5% over the past five years and the revisions for the year ended December 31, 2025 were approximately 2%.
See above discussion on the uncertainty of proved reserves estimates. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company did not record any impairment for the years ended December 31, 2024 or 2023. 54 Table of Contents Asset Retirement Obligations.
See above discussion on the uncertainty of proved reserves estimates. If capitalized costs exceed the ceiling limitation, the excess must be charged to expense. Once incurred, a write-down cannot be reversed at a later date. The Company did not record any impairment for the years ended December 31, 2025 and 2024. Asset Retirement Obligations.
The Company did not have significant revisions to its asset retirement obligations for the years ended December 31, 2024 or 2023. Income Taxes. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities.
The Company did not have significant revisions to its asset retirement obligations for the years ended December 31, 2025 and 2024. 54 Table of Contents Income Taxes. Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities.
Income tax (benefit) We recorded income tax benefit and expense of $22.2 million and $14.0 million for the years ended December 31, 2024 and 2023, respectively, which directly relates to movement in our valuation allowance against our deferred tax assets.
Income tax (benefit) We recorded income tax benefit of $5.5 million and $22.2 million for the years ended December 31, 2025 and 2024, respectively, which directly relates to movement in our valuation allowance against our deferred tax assets.
Conversely, during periods of declining market prices of oil, natural gas and NGL, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement. 46 Table of Contents Oil, Natural Gas and NGL Production and Pricing The table below presents production and pricing information for the years ended December 31, 2024 and 2023.
Conversely, during periods of declining market prices of oil, natural gas and NGL, our commodity derivative contracts may partially offset declining revenues and cash flow to the extent strike prices for our contracts are above market prices at the time of settlement. 47 Table of Contents Oil, Natural Gas and NGL Production and Pricing The table below presents production and pricing information.
The following table summarizes derivative activity for the years ended December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 2023 (Gain) loss on derivative contracts $ (748) $ (1,447) Realized settlement gains (losses) on derivative contracts $ 548 $ 5,876 Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded quarterly as a component of operating expenses.
The following table summarizes derivative activity (in thousands): Year Ended December 31, 2025 2024 (Gain) loss on derivative contracts $ (7,763) $ (748) Realized settlement gains (losses) on derivative contracts $ 5,189 $ 548 Our derivative contracts are not designated as accounting hedges and, as a result, changes in the fair value of our commodity derivative contracts are recorded quarterly as a component of operating expenses.
Our partial valuation allowance release of $50.6 million as of December 31, 2023 was increased by $22.2 million due to changes in expected future income, resulting in net deferred tax assets of $72.8 million as of December 31, 2024. We anticipate being able to utilize these deferred tax assets based on the generation of future income.
Our partial valuation allowance release of $72.8 million as of December 31, 2024 was increased by $5.5 million due to changes in expected future income, resulting in net deferred tax assets of $78.3 million as of December 31, 2025. We anticipate being able to utilize these deferred tax assets based on the generation of future income.
The decrease in interest income, net is due to the Company’s lower cash balance primarily as a result of our acquisitions, and to a lesser extent, capital expenditures and dividend payments.
The decrease in interest income, net is due to the Company’s lower cash balance primarily as a result of our capital expenditures, dividend payments, acquisitions and share repurchases as well as lower interest rates.
Working Capital and Sources and Uses of Cash Our principal sources of liquidity for 2025 include cash flow from operations and cash on hand. Our working capital decreased to $67.1 million at December 31, 2024, compared to $228.5 million at December 31, 2023.
Working Capital and Sources and Uses of Cash Our principal sources of liquidity for 2026 include cash flow from operations and cash on hand. Our working capital increased to $79.8 million at December 31, 2025, compared to $67.1 million at December 31, 2024.
“Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives. 49 Table of Contents Interest (income) expense, net for the years ended December 31, 2024 and 2023 consisted of the following (in thousands): Year Ended December 31, 2024 2023 Interest income (expense), net Interest income $ 7,875 $ 10,656 Interest expense Interest expense on letters of credit $ (40) $ (37) Interest expense on right of use assets (84) (64) Interest expense - other (7) (3) Total interest expense (131) (104) Total interest income (expense), net $ 7,744 $ 10,552 Interest (income) expense, net during the years ended December 31, 2024 and 2023 is primarily comprised of interest income received from cash deposits.
“Quantitative and Qualitative Disclosures about Market Risk” of this report for additional discussion of our commodity derivatives. 50 Table of Contents Interest income (expense), net consisted of the following (in thousands): Year Ended December 31, 2025 2024 Interest income (expense), net Interest income $ 4,149 $ 7,875 Interest expense Interest expense on right of use assets (90) (84) Interest expense on letters of credit (30) (40) Interest expense - other (342) (7) Total interest expense (462) (131) Total interest income (expense), net $ 3,687 $ 7,744 Interest income (expense), net during the years ended December 31, 2025 and 2024 is primarily comprised of interest income received from cash deposits.
Based on the SEC prices over the eleven months ended February 1, 2025 and NYMEX strip pricing for March 2025 as of February 28, 2025, we anticipate the SEC prices utilized in the March 31, 2025 full cost ceiling test may be $74.52 per barrel of oil and $2.44 per MMBtu of natural gas, (the "estimated first quarter prices").
Based on the SEC prices over the eleven months ended February 1, 2026 and NYMEX strip pricing for March 2026 as of February 26, 2026, we anticipate the SEC prices utilized in the March 31, 2026 full cost ceiling test may be $63.16 per barrel of oil and $3.72 per MMBtu of natural gas, (the "estimated first quarter prices").
The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2024 were $75.48 per barrel of oil and $2.13 per MMBtu of natural gas, before price differential adjustments.
The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2025 were $65.34 per barrel of oil and $3.39 per MMBtu of natural gas, before price differential adjustments.
Our capital expenditures for the years ended December 31, 2024 and 2023, are summarized below (in thousands): Year Ended December 31, 2024 2023 Capital Expenditures Drilling, completion, and capital workovers $ 15,562 $ 22,478 Leasehold and geophysical 11,246 (46) Capital expenditures, excluding acquisitions (on an accrual basis) 26,808 22,432 Acquisitions 129,664 11,232 Capital expenditures, including acquisitions 156,472 33,664 Changes in accounts payable and accrued expenses (263) 5,232 Inventory material transfers to oil and natural gas properties (141) (1,289) Total cash paid for capital expenditures, including acquisitions $ 156,068 $ 37,607 52 Table of Contents Cash Flows from Financing Activities Our financing activities used $73.7 million of cash for the year ended December 31, 2024, consisting primarily of $72.3 million in cash dividends, finance lease payments of $0.7 million, $0.4 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and $0.2 million in common stock repurchases.
Cash Flows from Investing Activities Our capital expenditures and acquisitions of oil and gas properties are summarized below (in thousands): Year Ended December 31, 2025 2024 Capital Expenditures Drilling, completion, and capital workovers $ 63,970 $ 15,562 Leasehold and geophysical 5,016 11,246 Capital expenditures, excluding acquisitions (on an accrual basis) 68,986 26,808 Acquisitions 8,514 129,664 Capital expenditures, including acquisitions 77,500 156,472 Changes in accounts payable and accrued expenses (10,372) (263) Inventory material transfers to oil and natural gas properties (3) (141) Total cash paid for capital expenditures, including acquisitions $ 67,125 $ 156,068 52 Table of Contents Cash Flows from Financing Activities Our financing activities used $23.3 million of cash for the year ended December 31, 2025, consisting primarily of $15.9 million in cash dividends, $6.4 million in common stock repurchases, finance lease payments of $0.7 million, $0.3 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise.
Overview We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent region ("Mid-Con"). Operational Activities For the year ended December 31, 2024, there were no operated wells drilled, with three operated and one non-operated wells completed.
Overview We are an independent oil and natural gas company with a principal focus on acquisition, development and production activities in the U.S. Mid-Continent region ("Mid-Con"). Operational Activities During the year ended December 31, 2025, the Company operated one drilling rig and drilled seven operated wells, and completed six wells.
See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail. Depreciation and Depletion of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are amortized using the unit-of-production method.
See Proved Reserves discussion in Part I, Item 1 of this Form 10-K for additional detail. Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation.
Our financing activities used $82.9 million of cash for the year ended December 31, 2023, consisting primarily of $81.5 million in cash dividends, $0.9 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and finance lease payments of $0.6 million offset by $0.1 million of proceeds from the exercise of stock options.
Our financing activities used $73.7 million of cash for the year ended December 31, 2024, consisting primarily of $72.3 million in cash dividends, finance lease payments of $0.7 million, $0.4 million of cash used for tax withholdings paid in exchange for shares withheld on employee vested stock awards that were settled by net exercise, and $0.2 million in common stock repurchases.
We did not record a full cost ceiling limitation impairment for the years ended December 31, 2024 or 2023. Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month SEC prices as adjusted for price differentials and other contractual arrangements.
Calculation of the full cost ceiling test is based on, among other factors, trailing twelve-month SEC prices as adjusted for price differentials and other contractual arrangements.
We expect our cash on hand and cash from operations to be adequate to meet our short and long-term liquidity needs. As of March 4, 2025 , the Company had no outstanding term or revolving debt obligations.
Liquidity and Capital Resources At December 31, 2025, our cash and cash equivalents, including restricted cash, was $112.3 million. We expect our cash on hand and cash from operations to be adequate to meet our short and long-term liquidity needs. As of February 26, 2026, the Company had no outstanding term or revolving debt obligations.
Year Ended December 31, 2024 2023 Change Production data (in thousands) Oil (MBbls) 918 1,047 (129) Natural gas (MMcf) 19,488 20,403 (915) NGL (MBbls) 1,889 1,705 184 Total volumes (MBoe) 6,056 6,152 (96) Average daily total volumes (MBoe/d) 16.5 16.9 (0.4) Average prices—as reported (1) Oil (per Bbl) $ 74.31 $ 74.69 $ (0.38) Natural gas (per Mcf) $ 1.10 $ 1.71 $ (0.61) NGL (per Bbl) $ 18.87 $ 20.83 $ (1.96) Total (per Boe) $ 20.69 $ 24.16 $ (3.47) Average prices—including impact of derivative contract settlements Oil (per Bbl) $ 74.88 $ 74.69 $ 0.19 Natural gas (per Mcf) $ 1.10 $ 2.00 $ (0.90) NGL (per Bbl) $ 18.89 $ 20.83 $ (1.94) Total (per Boe) $ 20.78 $ 25.11 $ (4.33) ___________________ (1) Prices represent actual average realized prices for the periods presented and do not include the impact of derivative transactions.
Year Ended December 31, 2025 2024 Change Production data (in thousands) Oil (MBbls) 1,214 918 296 Natural gas (MMcf) 19,802 19,488 314 NGL (MBbls) 2,254 1,889 365 Total volumes (MBoe) 6,768 6,056 712 Average daily total volumes (MBoe/d) 18.5 16.5 2.0 Average prices—as reported (1) Oil (per Bbl) $ 63.64 $ 74.31 $ (10.67) Natural gas (per Mcf) $ 2.10 $ 1.10 $ 1.00 NGL (per Bbl) $ 16.64 $ 18.87 $ (2.23) Total (per Boe) $ 23.10 $ 20.69 $ 2.41 Average prices—including impact of derivative contract settlements Oil (per Bbl) $ 64.80 $ 74.88 $ (10.08) Natural gas (per Mcf) $ 2.29 $ 1.10 $ 1.19 NGL (per Bbl) $ 16.69 $ 18.89 $ (2.20) Total (per Boe) $ 23.87 $ 20.78 $ 3.09 ___________________ (1) Prices represent actual average realized prices for the periods presented and do not include the impact of derivative transactions.
Cash Flows Our cash flows from operations are substantially dependent on current and future prices for oil, natural gas and NGL, which historically have been, and may continue to be, volatile.
We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events. Cash Flows Our cash flows from operations are substantially dependent on current and future prices for oil, natural gas and NGL, which historically have been, and may continue to be, volatile.
Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado. Other operating expense (income) increased for the year ended December 31, 2024 primarily due to a $1.3 million impairment on our equipment inventory.
Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing, the outsourcing of corporate functions and our exit from North Park Basin in Colorado. Other operating expense (income) decreased for the year ended December 31, 2025 primarily due to an impairment in 2024 on our non-full cost pool inventory.
Full cost pool impairments have no impact to our cash flow or liquidity. 48 Table of Contents Other Operating Expenses Other operating expenses for the years ended December 31, 2024 and 2023 consisted of the following (in thousands): Year Ended December 31, 2024 2023 Change General and administrative $ 11,695 $ 10,735 $ 960 Restructuring expenses 474 406 68 Employee termination benefits — 19 (19) (Gain) loss on derivative contracts (748) (1,447) 699 Other operating expense (income) 1,372 (157) 1,529 Total other operating expenses $ 12,793 $ 9,556 $ 3,237 General and administrative expenses increased for the year ended December 31, 2024 primarily due to higher personnel and other costs.
Full cost pool impairments have no impact to our cash flow or liquidity. 49 Table of Contents Other Operating Expenses Other operating expenses consisted of the following (in thousands): Year Ended December 31, 2025 2024 Change General and administrative $ 13,201 $ 11,695 $ 1,506 Restructuring expenses 1,060 474 586 (Gain) loss on derivative contracts (7,763) (748) (7,015) Other operating expense (income) — 1,372 (1,372) Total other operating expenses $ 6,498 $ 12,793 $ (6,295) General and administrative expenses increased for the year ended December 31, 2025 primarily due to higher personnel costs and professional fees.
For the year ended December 31, 2024, the Company repurchased 21,308 shares for $0.2 million. The Company did not repurchase any common stock under the existing or prior Program during the year ended December 31, 2023. Contractual Obligations and Off-Balance Sheet Arrangements At December 31, 2024, our contractual obligations included asset retirement obligations and short and long-term leases.
For the year ended December 31, 2025, the Company repurchased 595,635 shares for $6.4 million, or $10.72 per share. For the year ended December 31, 2024, the Company repurchased 21,308 shares for $0.2 million Contractual Obligations and Off-Balance Sheet Arrangements At December 31, 2025, our contractual obligations included asset retirement obligations and short and long-term leases.
As the partial valuation allowance release as of December 31, 2024 was higher than the partial valuation allowance release as of December 31, 2023 of $50.6 million, we recognized $22.2 million of deferred federal and state income tax benefit for the year ended December 31, 2024. 50 Table of Contents Liquidity and Capital Resources At December 31, 2024, our cash and cash equivalents, including restricted cash, was $99.5 million.
As the partial valuation allowance release as of December 31, 2025 was higher than the partial valuation allowance release as of December 31, 2024 of $72.8 million, we recognized $5.5 million of deferred federal and state income tax benefit for the year ended December 31, 2025.
Currently, these projects include (1) One rig development in the Cherokee Shale Play, which consists of 9 wells to be spud, 8 wells to be drilled and 6 wells to be completed in 2025 (2) Production Optimization program through artificial lift conversions to more efficient and cost-effective systems and high-graded recompletions (3) leasing program that will bolster future development and extend development in our Cherokee assets.
Currently, these projects include: (1) one-rig development in the Cherokee Shale Play (2) evaluation of accretive merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program (3) production optimization program through artificial lift conversions to more efficient and cost-effective systems and (4) a leasing program that will bolster future development and extend development in our Cherokee assets.
Payments Due by Period Total Less than 1 year 1-3 years 3-5 years More than 5 years (In thousands) Asset retirement obligations (1) $ 68,580 $ 9,131 $ — $ — $ 59,449 Operating lease 322 161 161 — — Short-term leases 2,196 2,196 — — — Finance lease 1,403 663 740 — — Total $ 72,501 $ 12,151 $ 901 $ — $ 59,449 ____________________ (1) Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2024.
Payments Due by Period Total Less than 1 year 1-3 years 3-5 years More than 5 years (In thousands) Asset retirement obligations (1) $ 72,391 $ 8,098 $ — $ — $ 64,293 Operating lease 161 161 — — — Short-term leases 7,817 7,817 — — — Finance lease 1,472 754 718 — — Total $ 81,841 $ 16,830 $ 718 $ — $ 64,293 ____________________ (1) Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2025.
Cash flows for the years ended December 31, 2024, and 2023 are presented in the following table and discussed below (in thousands): Year Ended December 31, 2024 2023 Cash flows provided by operating activities $ 73,933 $ 115,578 Cash flows used in investing activities (154,696) (36,164) Cash flows used in financing activities (1) (73,670) (82,938) Net (decrease) increase in cash, cash equivalents and restricted cash $ (154,433) $ (3,524) __________________ (1) Includes $72.3 million and $81.5 million in dividend payments for the year ended December 31, 2024 and 2023, respectively. 51 Table of Contents Cash Flows from Operating Activities The $41.6 million decrease in operating cash flows for the year ended December 31, 2024 compared to 2023, is primarily due to a decrease in revenues from lower commodity prices.
Cash flows are presented in the following table and discussed below (in thousands): Year Ended December 31, 2025 2024 Cash flows provided by operating activities $ 100,140 $ 73,933 Cash flows used in investing activities (64,011) (154,696) Cash flows used in financing activities (1) (23,295) (73,670) Net increase (decrease) in cash, cash equivalents and restricted cash $ 12,834 $ (154,433) __________________ (1) Includes $15.9 million and $72.3 million in dividend payments for the year ended December 31, 2025 and 2024, respectively.
Dividend payments for the year ended December 31, 2024 totaled $72.3 million, which included $0.5 million of dividends on vested stock awards. See Note 13 for further discussion of the Company’s dividends. Excluding any expenditures for acquisitions which may arise, we intend to spend between $66 million and $85 million in our 2025 capital budget plan.
Dividend payments, excluding shares issued in lieu of cash dividends, for the year ended December 31, 2025 totaled $15.9 million, which included $0.2 million of dividends on vested stock awards. See Note 13 for further discussion of the Company’s dividends.
If oil, natural gas and NGL prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced.
For example, during the period from January 1, 2021 through December 31, 2025, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $47.47 per Bbl, and the NYMEX Henry Hub spot prices for gas fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf. 51 Table of Contents If oil, natural gas and NGL prices decline from current levels, they could have a material adverse effect on our financial position, results of operations, cash flows and quantities of oil, natural gas and NGL reserves that may be economically produced.
The changes in operating assets and liabilities do not include changes in accounts payable or accrued expenses attributable to capital expenditures noted in the capital expenditure table below. See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.
See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses.
Consolidated Results of Operations The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs.
These and other factors, including reasonable reinvestment rates, maintaining our cash flows and prioritizing our regular-way dividend, will continue to shape our development decisions for the remainder of the year and beyond. Consolidated Results of Operations The majority of our consolidated revenues and cash flow are generated from the production and sale of oil, natural gas and NGLs.
The increase in depreciation and depletion for oil and natural gas properties was primarily the result of our acquisition in the Cherokee Play of the Western Anadarko Basin in the third quarter of 2024, which increased the book value of our proved properties and subsequently our depletion rate. Full cost pool impairment.
The increase in depreciation and depletion for oil and natural gas properties was primarily the result of an increase in our depletion rate and higher production volumes. Full cost pool impairment. We did not record a full cost ceiling limitation impairment for the years ended December 31, 2025 and 2024.
We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations and cash on hand. We will endeavor to keep our capital spending within or very close to our projected cash flows from operations subject to changing industry conditions or events.
Excluding any expenditures for acquisitions which may arise, we intend to spend between $76.0 million and $97.0 million in our 2026 capital budget plan. We intend to fund capital expenditures and other commitments for the next 12 months using cash flows from our operations and cash on hand.
Cash paid for oil and gas property acquisitions of $129.7 million, dividend payments to shareholders of $72.3 million, and $26.4 million in capital expenditures were the primary drivers in the reduction of working capital. These cash outflows were offset by $73.9 million in cash provided by operating activities.
The increase in working capital was primarily driven by cash flows provided by operating activities of $100.1 million and partially offset by $58.6 million in capital expenditures, dividend payments to stockholders of $15.9 million, $8.5 million in acquisitions and $6.4 million in share repurchases.
Our legacy non-Cherokee leasehold remains approximately 99% held by production, which cost-effectively maintains our development option over a reasonable tenor. We will continue to monitor forward-looking commodity prices, project results, costs and other factors that could influence returns and adjust capital allocations accordingly.
We will continue to monitor forward-looking commodity prices, project results, costs, impacts of tariffs and other factors that could influence returns and cash flows, and will adjust our program accordingly, to include curtailment of capital activity and wells, if needed, or conversely, well reactivations in higher commodity price environments.
Removed
For the year ended December 31, 2023 there were two operated wells drilled and four wells completed. The charts below show production and percent revenues by product for the years ended December 31, 2024 and 2023: The Company's production last year benefited from our previous drilling program that concluded in 2023.
Added
As of December 31, 2025, one operated well was being drilled and another operated well was awaiting completion. Additionally, four non-operated wells were drilled and completed during 2025. For the year ended December 31, 2024 there were no operated wells drilled, while three operated and one non-operated wells were completed.
Removed
On December 13, 2024, the Company closed a subsequent acquisition that exchanged and increased its ownership interest in certain proved and unproved oil and gas properties within the same area for $5.2 million, before customary post-closing adjustments of $0.5 million, paid in January 2025, and terminated the previously announced joint development agreement.
Added
During 2025, we issued 92,733 shares of common stock in lieu of cash dividends under the Dividend Reinvestment Plan. • On July 18, 2025, the Board increased its size from five members to six members and appointed Mr. Brett Icahn to serve as a member of the Board, effective as of August 1, 2025. Mr.
Removed
The Company will operate the majority of its planned development in 2025. • On September 30, 2024, and effective October 1, 2024, the Company announced the following changes (i) Jonathan Frates was appointed to serve as the Company's Executive Vice President and Chief Financial Officer and resigned as Chairman of the Board, (ii) the Board appointed Mr.
Added
Icahn's current term as a member of the Board will run until the 2026 annual meeting of stockholders. • Under our ongoing one-rig Cherokee development program we drilled seven operated wells, completed six operated wells during the year and turned six wells to sales during 2025. • We paid cash dividends to stockholders totaling $15.9 million or $0.46 per share in 2025, excluding stockholders who elected to take shares in lieu of cash under the Dividend Reinvestment Plan. • For the year ended December 31, 2025, we repurchased 595,635 shares of common stock for $6.4 million with a weighted average price of $10.72, under our share repurchase program. 46 Table of Contents Outlook We remain committed to growing the value of our asset base in a safe, responsible and efficient manner, while prudently allocating capital to high-return, growth projects.
Removed
Vincent Intrieri to serve as a Board member and as the Company’s Chairman of the Board to fill the vacancy following Jonathan Frates’ resignation from the Board; Mr. Intrieri also joined the Board’s Compensation and Nominating and Governance Committees, and (iii) Mr. Brandon Brown to serve as the Company’s Senior Vice President and Chief Accounting Officer, effective October 21, 2024.
Added
We are developing our term acreage in the Cherokee Play, and our total leasehold position, inclusive of the Cherokee, NW Stack and legacy assets, is approximately 95% held by production, which cost-effectively maintains our development option over a reasonable tenor.
Removed
Mr. Brown no longer serves as Chief Financial Officer upon the commencement of Mr. Frates’ role as Chief Financial Officer on October 21, 2024. • On April 3, 2024, the Company announced that the Board had appointed Mr.
Added
Revenues Consolidated revenues are presented in the table below (in thousands): Year Ended December 31, 2025 2024 Change Revenues Oil $ 77,270 $ 68,231 $ 9,039 Natural gas 41,587 21,397 20,190 NGL 37,500 35,662 1,838 Total revenues $ 156,357 $ 125,290 $ 31,067 Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2025 and 2024 are shown in the table below (in thousands): 2024 oil, natural gas and NGL revenues $ 125,290 Change due to production volumes 2025 25,556 Change due to average prices 2025 5,511 2025 oil, natural gas and NGL revenues $ 156,357 Oil, natural gas and NGL revenues increased during 2025 primarily due to new production volumes from our Cherokee play development program and higher natural gas price realizations partially offset by lower oil and NGL price realizations. 48 Table of Contents Operating Expenses Operating expenses consisted of the following (in thousands): Year Ended December 31, 2025 2024 Change Lease operating expenses $ 36,191 $ 40,012 $ (3,821) Production, ad valorem, and other taxes 9,846 6,780 3,066 Depreciation and depletion—oil and natural gas 36,439 25,976 10,463 Depreciation and amortization—other 6,433 6,503 (70) Total operating expenses $ 88,909 $ 79,271 $ 9,638 Lease operating expenses ($/Boe) $ 5.35 $ 6.61 $ (1.26) Production, ad valorem, and other taxes ($/Boe) $ 1.45 $ 1.12 $ 0.33 Depreciation and amortization—oil and natural gas ($/Boe) $ 5.38 $ 4.29 $ 1.09 Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 6.3 % 5.4 % 0.9 % Lease operating expenses decreased in total and per Boe versus the same period in 2024 primarily due to $4.3 million of out of period corrections which are non-recurring, non-cash, adjustments of operating accruals dating as far back as the Company’s emergence from bankruptcy (see “Note 1—Summary of Significant Accounting Policies” to the accompanying consolidated financial statements included in Item 8 of this Form 10-K for further information), of which $2.1 million and $2.2 million were recorded in the second and fourth quarter of 2025, respectively.
Removed
Dean Parrish, Senior Vice President, Operations, to serve as the Company’s Senior Vice President and Chief Operating Officer, effective April 1, 2024. 45 Table of Contents Outlook We remain committed to growing the value of our asset base in a safe, responsible and efficient manner, while prudently allocating capital to high-return, organic growth projects.
Added
The removal of the operating accruals was partially offset by an increase in water hauling costs associated with increased activity from our 2025 development program. Production, ad valorem, and other taxes increased due to higher average commodity prices, sales volumes, and related revenues.
Removed
These and other factors, to include reasonable reinvestment rates, sustaining our cash flows and prioritizing our regular-way dividend, will continue to shape our development decisions for the remainder of the year and beyond. We also remain vigilant in evaluating further merger and acquisition opportunities, with consideration of our strong balance sheet and commitment to our capital return program.
Added
The increase in sales volumes was primarily the result of our one rig development program in the Cherokee Play of the Mid-Con. Production, ad valorem, and other taxes per Boe increased primarily due to higher average commodity prices.
Removed
Revenues Consolidated revenues for the years ended December 31, 2024 and 2023 are presented in the table below (in thousands).
Added
Cash Flows from Operating Activities The increase in cash flows from operations for the year ended December 31, 2025 compared to the same period in 2024 is primarily due to an increase in revenues from higher sales volumes from our 2025 development program in the Cherokee Play of the Mid-Continent region with our base production also benefiting from our 2024 acquisition and higher natural gas price realizations.
Removed
Year Ended December 31, 2024 2023 Change Revenues Oil $ 68,231 $ 78,174 $ (9,943) Natural gas 21,397 34,941 (13,544) NGL 35,662 35,526 136 Total revenues $ 125,290 $ 148,641 $ (23,351) Variances in oil, natural gas and NGL revenues attributable to changes in the average prices received for our production and total production volumes sold for the years ended December 31, 2024 and 2023 are shown in the table below (in thousands): 2023 oil, natural gas and NGL revenues $ 148,641 Change due to production volumes in 2024 (2,001) Change due to average prices in 2024 (21,350) 2024 oil, natural gas and NGL revenues $ 125,290 47 Table of Contents Oil, natural gas and NGL revenues decreased primarily due to lower commodity prices.
Removed
The Company's production benefited from its prior drilling program, concluded in 2023, as well as production from our newly acquired wells beginning in September 2024, offset by the natural decline of our producing assets.
Removed
Operating Expenses Operating expenses for the years ended December 31, 2024 and 2023 consisted of the following (in thousands): Year Ended December 31, 2024 2023 Change Lease operating expenses $ 40,012 $ 41,862 $ (1,850) Production, ad valorem, and other taxes 6,780 10,870 (4,090) Depreciation and depletion—oil and natural gas 25,976 15,657 10,319 Depreciation and amortization—other 6,503 6,518 (15) Total operating expenses $ 79,271 $ 74,907 $ 4,364 Lease operating expenses ($/Boe) $ 6.61 $ 6.80 $ (0.19) Production, ad valorem, and other taxes ($/Boe) $ 1.12 $ 1.77 $ (0.65) Depreciation and amortization—oil and natural gas ($/Boe) $ 4.29 $ 2.54 $ 1.75 Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 5.4 % 7.3 % (1.9) % The decrease in lease operating expenses was primarily due to a decrease in workover expense.
Removed
Production, ad valorem, and other taxes decreased primarily due to a $1.4 million ad valorem tax refund received in the fourth quarter of 2024 combined with a decrease in production taxes due to lower commodity prices and related revenues.
Removed
In January 2024, the Board approved a one-time cash dividend of $1.50 per share of the Company's common stock, which was paid on February 20, 2024 to shareholders of record as of the close of business on February 5, 2024. The aggregate total payout was approximately $55.6 million.
Removed
Additionally, in March 2024, the Board increased the on-going quarterly dividend to $0.11 per share which was paid in March, May, August, and November 2024. The aggregate total payout was $16.3 million. The $0.11 per share dividend is subject to quarterly approval by the Board.
Removed
For example, during the period from January 2020 through December 2024, the NYMEX WTI settled price for oil fluctuated between a high of $123.64 per Bbl and a low of $(36.98) per Bbl, and the NYMEX Henry Hub spot prices for gas fluctuated between a high of $24.77 per Mcf and a low of $1.26 per Mcf.
Removed
Cash Flows from Investing Activities During the year ended December 31, 2024, cash flows used in investing activities primarily reflects $129.7 million in cash paid for oil and gas property acquisitions and capital expenditures of $26.4 million. Cash outflows were partially offset by $1.4 million of proceeds from the sale of equipment related to our oil and gas assets.
Removed
During the year ended December 31, 2023, cash flows used in investing activities primarily reflects capital expenditures of $26.4 million made for drilling and completions, capital workovers, and well reactivations and $11.2 million related to an acquisition of proved reserves, which increased ownership interests in properties operated by the Company.
Removed
Cash outflows were partially offset by $1.5 million of proceeds from the sale of equipment related to our oil and gas assets. See "Note 3 — Acquisitions of Assets and Oil and Gas Properties" to the accompanying consolidated financial statements included in Item 8 of this report for additional information. Capital Expenditures.
Removed
Under this method, depreciation and depletion is computed at the end of each quarter by multiplying total production for the quarter by a depletion rate. The depletion rate is determined by dividing the total unamortized cost base plus future development costs by net equivalent proved reserves at the beginning of the quarter.
Removed
See above discussion on the uncertainty of proved reserves estimates. If we maintain the same level of production year over year, the depreciation and depletion of oil and natural gas properties may be significantly different if our estimate of remaining reserves or future development costs changes significantly.
Removed
The average rates used for depreciation and depletion of oil and natural gas properties were $3.52 per Boe in 2024 and $1.82 per Boe in 2023. Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

3 edited+0 added−0 removed10 unchanged
Biggest changeAt December 31, 2024, we had the following open commodity derivative contracts: Period Type of Derivative Instrument Index (1) Daily Volume (Bbl) Weighted Average Price Per Barrel January 2025 - December 2025 Swaps Mont Belvieu OPIS 300 $ 39.69 January 2025 - December 2025 Swaps NYMEX WTI 500 $ 71.60 January 2026 - June 2026 Swaps NYMEX WTI 300 $ 68.67 (1) NGL swaps exclude ethane Because we historically have not designated any of our derivative contracts as hedges for accounting purposes, changes in the fair value of our derivative contracts were recognized as gains and losses in current period earnings.
Biggest changeAt December 31, 2025, we had the following open commodity derivative contracts: Period Index Daily Volume Weighted Average Price Oil (Bbl) Fixed Price Swaps January 2026 - June 2026 NYMEX WTI 300 $68.67 Natural Gas (MMBtu) Fixed Price Swaps January 2026 - December 2026 NYMEX Henry Hub 11,797 $4.16 Producer Costless Collars January 2026 - December 2026 NYMEX Henry Hub 4,500 $3.35 Put / $5.35 Call Because we historically have not designated any of our derivative contracts as hedges for accounting purposes, changes in the fair value of our derivative contracts were recognized as gains and losses in current period earnings.
Credit Risk. As applicable, we were exposed to credit risk related to counterparties to our derivative financial contracts. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions.
As applicable, we were exposed to credit risk related to counterparties to our derivative financial contracts. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative transactions in over-the-counter markets involves the risk that the counterparties may be unable to meet the financial terms of the transactions.
The following table summarizes derivative activity for the years ended December 31, 2024 and 2023 (in thousands): Year Ended December 31, 2024 2023 (Gain) loss on derivative contracts $ (748) $ (1,447) Realized settlement gains (losses) on derivative contracts $ 548 $ 5,876 See “Note 6—Derivatives” to the accompanying consolidated financial statements in Item 8 of this report for additional information regarding our commodity derivatives.
The following table summarizes derivative activity (in thousands): Year Ended December 31, 2025 2024 (Gain) loss on derivative contracts $ (7,763) $ (748) Realized settlement gains (losses) on derivative contracts $ 5,189 $ 548 See “Note 6—Derivatives” to the accompanying consolidated financial statements in Item 8 of this report for additional information regarding our commodity derivatives. Credit Risk.

Other SD 10-K year-over-year comparisons