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What changed in SANDRIDGE ENERGY INC's 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of SANDRIDGE ENERGY INC's 2023 and 2024 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2024 report.

+220 added−213 removedSource: 10-K (2025-03-11) vs 10-K (2024-03-07)

Top changes in SANDRIDGE ENERGY INC's 2024 10-K

220 paragraphs added · 213 removed · 168 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

58 edited+28 added−8 removed176 unchanged
Biggest changeThe Meramec is composed of interbedded shales, sands, and carbonates while the Osage is composed of low porosity, fractured limestone and chert. The top of these target formations ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin.
Biggest changeThe top of this target formation ranges in depth from about 5,800 feet at the northern edge of the basin to greater than 14,000 feet toward the interior of the basin. Meramec formation thickness ranges from about 50 feet to over 400 feet. The Woodford Shale is the primary hydrocarbon source for the Meramec.
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 in its review.
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.
State agencies in Kansas and Oklahoma 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, decommissioning and site restoration. Natural Gas Sales and Transportation The availability, terms and cost of transportation significantly affect sales of oil and natural gas.
Compliance with this new rule, and any future air pollution control and permitting requirements, has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which could be significant.
Compliance with this rule, and any future air pollution control and permitting requirements, has the potential to delay the development of oil and natural gas projects and increase our costs of development and production, which could be significant.
The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties in excess of one million dollars per day per violation. 22 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 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.
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; 21 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; 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.
At COP27 in Sharm El-Sheik in November 2022, the Biden Administration unveiled an updated U.S. Methane Emissions Reduction Action Plan, building upon the first plan released at COP26. Most recently, at COP28, the Biden Administration announced the new technology standards pursuant to the CAA for reduced methane emissions, as discussed above in this disclosure.
At COP27 in Sharm El-Sheik in November 2022, the Biden Administration unveiled an updated U.S. Methane Emissions Reduction Action Plan, building upon the first plan released at COP26. At COP28, the Biden Administration announced the new technology standards pursuant to the CAA for reduced methane emissions, as discussed above in this disclosure.
The BLM issued a final rule repealing the 2015 hydraulic fracturing rule in December 2017. 20 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.
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.
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, 2023.
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.
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.” After considering comments on the November 2021 and November 2022 proposed rulemakings, on December 2, 2023, the EPA announced its final rule under the CAA to reduce methane emissions from the oil and natural gas industry.
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.” On December 2, 2023, the EPA announced its final rule under the CAA to reduce methane emissions from the oil and natural gas industry.
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, 2023.
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.
Preparation of Reserves Estimates Approximately 95 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 97.5 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.
(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, 2023. We operate the majority of all wells in which we owned a working interest at December 31, 2023 and 2022.
(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.
However, the Paris Agreement does not impose any binding obligations on the United States. In June 2017, the United States announced it would withdraw from the Paris Agreement, which became effective November 4, 2020. The United States has rejoined the Paris Agreement as of February 19, 2021.
However, the Paris Agreement does not impose any binding obligations on the United States. In June 2017, the United States announced it would withdraw from the Paris Agreement, which became effective November 4, 2020. The United States later rejoined the Paris Agreement as of February 19, 2021.
While compliance with the ESA, MBTA and BGEPA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered or other protected species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective 19 Table of Contents measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.
While compliance with the ESA, MBTA and BGEPA has not had an adverse effect on our exploration, development and production operations in areas where threatened or endangered or other protected species or their habitat are known to exist, it may require us to incur increased costs to implement mitigation or protective measures and also may delay, restrict or preclude drilling activities in those areas or during certain seasons, such as breeding and nesting seasons.
We had 102 full-time employees, including 87 field employees and 15 corporate employees at December 31, 2022. Health, Safety and Environment Our people are a key driver to our success in Health, Safety and Environment ("HSE") related outcomes.
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.
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, 2023 is filed with this report as Exhibit 99.1. Cawley, Gillespie & Associates prepared reserves for our Mid-Continent properties located in Kansas and Oklahoma as of December 31, 2023.
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.
For additional information regarding changes in proved reserves during each of the three years ended December 31, 2023, 2022 and 2021 see “Note 18—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, 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.
Reporting of Natural Gas Liquids NGLs are recovered through further processing of a portion of our natural gas production stream. At December 31, 2023, NGLs comprised approximately 29% 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, 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.
F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 17, 2024, 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.
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.
Our primary operations are the production, development and acquisition of hydrocarbon resources. The following table presents information concerning our operations as of December 31, 2023.
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.
The percentage of total proved reserves prepared by the independent petroleum consultants is shown in the table below. December 31, 2023 2022 Cawley, Gillespie & Associates, Inc. 95.2 % 95.0 % Total 95.2 % 95.0 % The remaining 4.8% and 5.0% of estimated proved reserves as of December 31, 2023 and 2022 were based on internally prepared estimates.
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.
Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 36 years of practical experience in petroleum engineering, with over 34 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 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.
Allen graduated from the University of Oklahoma with a Master’s in Business Administration. Mr. Allen has over 14 years of practical experience in petroleum engineering with 9 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 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.
On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”).
On an international level, the United States agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measure each country will use to achieve its GHG emissions targets, (the “Paris Agreement”).
Year Ended December 31, 2023 2022 Production data (in thousands) Oil (MBbls) 1,047 949 Natural gas (MMcf) 20,403 21,101 NGL (MBbls) 1,705 1,997 Total volumes (MBoe) 6,152 6,463 Average daily total volumes (MBoe/d) 16.9 17.7 Average prices—as reported (1) Oil (per Bbl) $ 74.69 $ 92.21 Natural gas (per Mcf) $ 1.71 $ 4.88 NGL (per Bbl) $ 20.83 $ 31.88 Total (per Boe) $ 24.16 $ 39.34 Expenses per Boe Production costs (2) $ 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, 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.
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, 2023 and 2022, of which approximately 95% for each year 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.
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.
During 2023, 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
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
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.
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.
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, 2023, we had 102 full-time employees, including 87 field employees and 15 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. HUMAN CAPITAL As of December 31, 2024, we had 104 full-time employees, including 85 field employees and 19 corporate employees.
The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity zone(s) ranging between 20 and 150 feet in thickness. The Meramec and Osage Formations are Mississippian in age, lying above the Woodford Shale and below Chester formations.
The Mississippian formation is approximately 350 to 650 feet in gross thickness across our lease position and has targeted porosity zone(s) ranging between 20 and 150 feet in thickness. The Meramec Formation is Mississippian in age, lying above the Woodford Shale and below Chester formations. The Meramec is composed of interbedded shales, sands, and carbonates.
Notably, several states where we operated as of December 31, 2023, have already adopted rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions.
Notably, several states where we operate have adopted similar rules requiring operators of both new and existing sources to develop and implement an LDAR program and to install devices on certain equipment to capture 95 percent of methane emissions.
(3) Estimated proved reserves as of December 31, 2023 divided by net production for the year ended December 31, 2023. (4) Average economic reserve life using SEC prices and weighted for reserve volumes at December 31, 2023. Properties Mid-Continent We held interests in 548,895 gross (364,201 net) leasehold acres located primarily in Oklahoma and Kansas at December 31, 2023.
(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.
The following table provides a reconciliation of our PV-10 to Standardized Measure: December 31, 2023 2022 (In thousands) PV-10 $ 296,293 $ 810,663 Present value of future income tax discounted at 10% $ — $ (3,798) Standardized Measure of Discounted Net Cash Flows $ 296,293 $ 806,865 Proved Reserves - Mid-Continent .
The 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 .
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.
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.
December 31, 2023 2022 Estimated Proved Reserves (1) Developed Oil (MMBbls) 7.1 8.4 Natural gas (Bcf) 194.4 242.8 NGL (MMBbls) 16.2 25.4 Total proved developed (MMBoe) 55.7 74.3 Undeveloped Oil (MMBbls) — — Natural gas (Bcf) — — NGL (MMBbls) — — Total proved undeveloped (MMBoe) — — Total Proved Oil (MMBbls) 7.1 8.4 Natural gas (Bcf) 194.4 242.8 NGL (MMBbls) 16.2 25.4 Total proved (MMBoe) 55.7 74.3 Standardized Measure of Discounted Net Cash Flows (in millions) (2) $ 296.3 $ 806.9 PV-10 (in millions) (3) $ 296.3 $ 810.7 ____________________ (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.
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.
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, 2023 $ 78.22 $ 2.64 $ 76.65 $ 21.53 $ 1.62 December 31, 2022 $ 93.67 $ 6.36 $ 93.73 $ 33.42 $ 4.76 ____________________ (a) Index prices are based on average WTI Cushing spot prices for oil and average Henry Hub spot market prices for natural gas.
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.
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 55.7 16.9 9.0 29.8 548,895 364,201 ____________________ (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 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.
Associated proved reserves at December 31, 2023 totaled 55.7 MMBoe, all of which were proved developed reserves. Our interests in the Mid-Continent as of December 31, 2023 included 1,453 gross (849 net) producing wells with an average working interest of 58.4%. The interests are largely aggregated across the Mississippian Lime, Meramec and Osage formations.
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.
We will continue to exercise financial discipline and prudent capital allocation to projects we believe provide a high rate of return in the current commodity price environment, and will remain vigilant and maintain optionality for opportunistic, value-accretive acquisitions and business combinations. 6 Table of Contents PRIMARY BUSINESS OPERATIONS A comparative discussion of our 2022 to 2021 operating results can be found in Item 1 “Business” included in our Annual Report on Form 10-K for the year ended December 31, 2022 filed with the SEC on March 15, 2023.
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.
Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works.
Also, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending wastewater to publicly owned treatment works. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs.
In addition, we could find ourselves subject to third party lawsuits alleging damages resulting from seismic events that occur in our areas of operation. 17 Table of Contents 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 because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes.
Oil Natural Gas Total Gross Net Gross Net Gross Net Geographic Area Mid-Continent 1,133 650 320 199 1,453 849 Drilling Activity 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.
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.
The Woodford Shale is the primary hydrocarbon source for both the Meramec and Osage. 7 Table of Contents Proved Reserves The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data.
Depths of the top of the Cherokee within the Western Anadarko Basin range from approximately 8,500 feet north of the basin to greater than 13,000 feet basinward, with a thickness ranging from 400 feet to greater than 2,500 feet. 7 Table of Contents Proved Reserves The portion of a reservoir considered to contain proved reserves includes (i) the portion identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil, natural gas or NGLs on the basis of available geoscience and engineering data.
As of December 31, 2023, we had an interest in 1,453 gross (849 net) producing wells, approximately 958 of which we operate, and 548,895 gross (364,201 net) total acres under lease. As of December 31, 2023, we had no active drilling rigs. Total estimated proved reserves as of December 31, 2023, were 55.7 MMBoe, all of which were proved developed.
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.
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 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.
At the 26th Conference of the Parties to the United Nations Framework Convention of Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union launched the Global Methane Pledge, an initiative to reduce global methane emissions by at least 30% from 2020 levels by 2030.
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. 19 Table of Contents At the 26th Conference of the Parties to the United Nations Framework Convention of Climate Change (“COP26”) in Glasgow in November 2021, the United States and the European Union launched the Global Methane Pledge, an initiative to reduce global methane emissions by at least 30% from 2020 levels by 2030.
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.
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.
As of December 31, 2023, 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, 2024 — — December 31, 2025 — — December 31, 2026 246 19 December 31, 2027 and later — — Total (1) 246 19 ____________________ (1) The Company has 60,932 gross (26,051 net) undeveloped acres not subject to expiration.
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.
It is not possible at this time to predict how or when the United States might impose further restrictions on GHGs as a result of the Paris Agreement, and the full impact of actions at COP28 remain uncertain at this time.
It is not possible at this time to predict how or if the United States or states might impose further restrictions on GHGs.
The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities.
Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities.
Furthermore, on January 12, 2024, EPA announced a proposed rulemaking to reduce methane emissions from the oil and gas sector pursuant to the Inflation Reduction Act.
This rule and any future revisions thereto will continue to require oil and gas operators to expend material sums. 18 Table of Contents Furthermore, on January 12, 2024, EPA announced a proposed rulemaking to reduce methane emissions from the oil and gas sector pursuant to the Inflation Reduction Act. The rule was finalized on November 12, 2024.
If finalized, the rule will assess a charge on larger emitters of waste methane that exceed emissions intensity levels set by Congress in the Inflation Reduction Act. 18 Table of Contents In addition, in November 2016, the U.S.
The rule assesses a charge called a Waste Emissions Charge on larger emitters of waste methane if their emissions exceed specific performance levels set by Congress in the Inflation Reduction Act.
Our Business Strategy The Company’s primary strategic focus is to grow the value and cash generation capability of our asset base in a safe, responsible and efficient manner, and will seek to use our net operating loss carry forwards to minimize income taxes and maximize cash flow.
Any materials that we have filed with the SEC may be accessed via the SEC’s website address at www.sec.gov. Our Business Strategy The Company’s primary strategic focus is to grow the value of our asset base in a safe, responsible and efficient manner, while utilizing our net operating loss carry forwards to maximize cash flow.
Proved reserves decreased from 74.3 MMBoe at December 31, 2022 to 55.7 MMBoe at December 31, 2023, primarily due to a decrease in year-end SEC commodity prices for oil and natural gas, price realizations and NGL yield which resulted in a decrease of 17.5 MMBoe, as well as 6.2 MMBoe from the Company's production during 2023, 1.4 MMBoe attributable to well shut-ins and other revisions, and 0.1 MMBoe in sales.
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.
Developed and Undeveloped Acreage The following table presents information regarding our developed and undeveloped acreage at December 31, 2023. Developed Acreage Undeveloped Acreage Gross Net Gross Net Geographic Area Mid-Continent 487,717 338,131 61,178 26,070 12 Table of Contents Less than 5% of the leases included in the 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 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.
During the year ended December 31, 2022, there were eight operated wells drilled, with one third-party rig actively drilling on our operated acreage and two wells awaiting completion. Additionally, we participated in one non-operated well that was drilled during the year ended December 31, 2022, and was completed during year ended December 31, 2023.
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.
The Company also had positive revisions including purchases of 1.8 MMBoe, extensions of 1.2 MMBoe, 1.9 MMBoe associated with well positive performance revisions, and 1.7 MMBoe associated with other commercial improvements. Proved Undeveloped Reserves. There were no proved undeveloped reserves at December 31, 2023 and 2022.
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.
Removed
Any materials that we have filed with the SEC may be accessed via the SEC’s website address at www.sec.gov.
Added
We will continue to exercise financial discipline and prudent capital allocation to projects we believe provide a high rate of return in the current commodity price environment, to include executing our planned development within the Cherokee play.
Removed
Meramec formation thickness ranges from about 50 feet to over 400 feet and the Osage formation thickness ranges from about 450 to 1,400 feet.
Added
The Cherokee Formation of the Western Anadarko Basin has become a prolific hydrocarbon producer with increased horizontal activity over the last few years. Pennsylvanian in age, the Cherokee overlies the Atoka and is overlain by the Marmaton Group. The Cherokee Formation is comprised of mostly self-sourcing shales with interbedded high porosity sands.
Removed
This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs. 16 Table of Contents Finally, the Oil Pollution Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States.
Added
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.
Removed
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.
Added
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.
Removed
This new rule and any future revisions thereto will continue to require oil and gas operators to expend material sums. States will have two years to review and develop an implementation plan and they must set compliance dates within three years of that.
Added
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.
Removed
If finalized, the proposed rule would require various technology upgrades, impose limits related to flaring, and require LDAR plans. The final rule was not issued in 2023 as initially expected but is expected to be announced later this year.
Added
This review is ongoing. We note that in January 2025, EPA dismissed all of the members of the CASAC and announced it is working to update the committee membership.
Removed
Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations.
Added
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.
Removed
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.
Added
With this order, President Trump grants federal agencies the authority to use various emergency powers to facilitate the “identification, leasing, siting, production, transportation, refining, and generation of domestic energy resources.” One provision of this order directs the EPA and Corps to use the emergency Army Corps permitting provisions under the Clean Water Act and the Rivers and Harbos Act to streamline permitting reviews.
Added
In addition, we could find ourselves subject to third party lawsuits alleging damages resulting from seismic events that occur in our areas of operation.
Added
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.
Added
After the rule was issued, EPA issued an interim final rule effective in August 2024 to make technical, non-substantive corrections to the rule. In addition, in May 2024, EPA granted industry petitioners’ request for reconsideration on two aspects of the rule related to monitoring and emergency operations for flares.
Added
On December 20, 2024, EPA proposed discrete technical revisions to these two provisions. The proposed revisions were published to the Federal Register on January 15, 2025. The proposed amendments only address petitions for reconsideration and do not propose changes to other aspects of the final rule.
Added
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.
Added
Also, as directed by Congress, the Waste Emissions Charge starts at $900 per metric ton of wasteful emissions in CY 2024, increasing to $1,200 for CY 2025, and $1,500 for CY 2026 and beyond, and only applies to emissions that exceed statutorily specified methane intensity levels. On February 4, 2025, members of the U.S.

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Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

43 edited+9 added−16 removed166 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 ◦ Changes affecting the availability of the London Inter-bank Offered Rate (“LIBOR”) may have consequences for us that cannot yet be reasonably predicted ◦ 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 ◦ 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 24 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.
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.
We maintained effective internal control over financial reporting as of December 31, 2023, 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, 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.
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. 27 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. 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.
As of December 31, 2023, 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, 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.
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. 28 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. 29 Table of Contents Future price declines may result in reductions of the asset carrying values of our oil and natural gas properties.
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; 39 Table of Contents • 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 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.
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, 2023 or 2022.
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.
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; • 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; 26 Table of Contents • 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; 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.
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.
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.
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. 31 Table of Contents 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. Oil and natural gas wells are subject to operational hazards that can cause substantial losses for which we may not be adequately insured.
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.
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.
We may outsource other functions in the future, which would increase our reliance on third parties. 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. 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.
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. 34 Table of Contents From time to time, the U.S.
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.
If oil, natural gas and NGL prices decline further in the near term, and without other mitigating circumstances, we may experience additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which would likely cause us to record additional write-downs of capitalized costs of oil and natural gas properties and non-cash charges against future earnings.
If oil, natural gas and NGL prices decline in the near term, and without other mitigating circumstances, we may experience additional losses of future net revenues, including losses attributable to quantities that cannot be economically produced at lower prices, which could cause us to record additional write-downs of capitalized costs of oil and natural gas properties and non-cash charges against future earnings.
Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. 36 Table of Contents The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") created a new regulatory framework for oversight of derivatives transactions by the CFTC and the SEC.
Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative contracts. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") created a new regulatory framework for oversight of derivatives transactions by the CFTC and the SEC.
Repercussions of natural disasters or severe weather conditions may include: • evacuation of personnel and curtailment of operations; • damage to drilling rigs or other facilities, resulting in suspension of operations; 30 Table of Contents • inability to deliver materials to worksites; and • damage to, or shutting in of, pipelines and other transportation facilities.
Repercussions of natural disasters or severe weather conditions may include: • evacuation of personnel and curtailment of operations; • damage to drilling rigs or other facilities, resulting in suspension of operations; • inability to deliver materials to worksites; and • damage to, or shutting in of, pipelines and other transportation facilities.
Additionally, inflation can impact the economics of future projects which could result in reduced investment activity and our ability to offset natural declines. 32 Table of Contents As we outsource functions, we become more dependent on the entities performing those functions. Disruptions or delays at our third-party service providers could adversely impact our operations.
Additionally, inflation can impact the economics of future projects which could result in reduced investment activity and our ability to offset natural declines. As we outsource functions, we are more dependent on the entities performing those functions. Disruptions or delays at our third-party service providers could adversely impact our operations.
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 2019 through December 2023.
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.
Cumulative full cost ceiling impairment from the Emergence Date through December 31, 2023 totaled $947.1 million.
Cumulative full cost ceiling impairment from the Emergence Date through December 31, 2024 totaled $947.1 million.
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 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; • energy conservation and environmental measures; • the price and availability of alternative fuels and energy sources; 25 Table of Contents • 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; • 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.
For oil, from January 2019 through December 2023, 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 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.
The ability to attract and retain key personnel is critical to the success of our business and the loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations. The success of our business depends on key personnel, including members of senior management and technical personnel.
The ability to attract and retain key personnel is critical to the success of our business and the loss of senior management or technical personnel or our inability to hire additional qualified personnel could adversely affect our operations.
Each right entitles its holder, under certain circumstances, to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock at an exercise price of $5.00 per right, subject to adjustment.
Each share of our common stock issued thereafter will also include one right. Each right entitles its holder, under certain circumstances, to purchase from us one one-thousandth of a share of our Series A Junior Participating Preferred Stock at an exercise price of $5.00 per right, subject to adjustment.
For natural gas, from January 2019 through December 2023, the NYMEX Henry Hub spot prices fluctuated between a high of $24.77 per Mcf and a low of $1.38 per Mcf.
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.
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.
“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.
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.
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.
The Tax Benefits Preservation Plan was approved at the 2021 annual meeting of stockholders on May 25, 2021. On June 14, 2023, our Board of Directors approved an amendment to the Tax Benefits Preservation Plan 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 14, 2023, our Board of Directors approved an amendment to the Tax Benefits Preservation Plan 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.
Under the EPAct 2005 and implementing regulations, the FERC prohibits market manipulation in connection with the purchase or sale of natural gas. The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with respect to certain segments of the physical and futures energy commodities market including oil and natural gas.
The CFTC has similar authority under the Commodity Exchange Act and regulations it has promulgated thereunder with respect to certain segments of the physical and futures energy commodities market including oil and natural gas.
These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations, increase direct and third-party post production costs or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid for transportation on downstream interstate pipelines. 33 Table of Contents 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.
These and other potential regulations could increase our operating costs, reduce our liquidity, delay our operations, increase direct and third-party post production costs or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows and which could reduce cash received by or available for distribution, including any amounts paid for transportation on downstream interstate pipelines.
As of December 31, 2023, we hold 364,201 total net acres (including developed and undeveloped net acres), of which 26,070 net aces is undeveloped. Of our undeveloped acreage, less than 5% 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, 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.
Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers. All of the foregoing may adversely affect our business, financial condition, results of operations, and cash flows. Future drilling activities face substantial uncertainties.
Negative economic conditions could also adversely affect the collectability of our trade receivables or performance by our vendors and suppliers. All of the foregoing may adversely affect our business, financial condition, results of operations, and cash flows. Rising international tariffs could further contribute to economic uncertainty and market volatility.
We cannot assure that we will be successful in attracting or retaining such personnel. We may need to enter into retention or other arrangements that could be costly to maintain.
The market for qualified personnel has historically been, and we expect that it will continue to be, intensely competitive. We cannot assure that we will be successful in attracting or retaining such personnel. We may need to enter into retention or other arrangements that could be costly to maintain.
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.
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.
A cybersecurity incident of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations. 37 Table of Contents We have programs, processes and technologies in place to attempt to prevent, detect, contain, respond to and mitigate security-related threats and potential incidents, as well as internal accounting controls to prevent unauthorized or fraudulent payments by ensuring that transactions are executed only with management authorization.
We have programs, processes and technologies in place to attempt to prevent, detect, contain, respond to and mitigate security-related threats and potential incidents, as well as internal accounting controls to prevent unauthorized or fraudulent payments by ensuring that transactions are executed only with management authorization.
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. 35 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.
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.
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.
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.
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.
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.
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.
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.
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.
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.
The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the business and changes we may make to the organizational structure to adjust to changing circumstances. The market for qualified personnel has historically been, and we expect that it will continue to be, intensely competitive.
The success of our business depends on the continuity of information and processes, key personnel, including members of senior management and technical personnel. The ability to attract and retain these key personnel may be difficult in light of the uncertainties currently facing the industry and changes we may make to the organizational structure to adjust to changing circumstances.
However, there is no assurance that the Tax Benefits Preservation Plan will prevent all transfers that could result in such an “ownership change.” Risks Relating to Our Common Stock We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover.
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.
In particular, cash flow from operations were $115.6 million and $164.7 million for the years ended December 31, 2023 and 2022, respectively. We are not actively trying to raise debt or equity capital at this time, with current projected activity for the year financed by cash flow from operations or cash held on the balance sheet.
While we may seek to raise debt or equity capital to fund high return projects or acquisitions, we expect our current projected activity for the year to be financed by cash flow from operations or cash held on the balance sheet.
Removed
“Legal Proceedings” for additional information. 29 Table of Contents Changes affecting the availability of the London Inter-bank Offered Rate (“LIBOR”) may have consequences for us that cannot yet be reasonably predicted. The LIBOR benchmark has been the subject of national, international and other regulatory guidance and proposals to reform.
Added
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.
Removed
In July 2017, the United Kingdom Financial Conduct Authority (the authority that regulates LIBOR) announced that it intends to stop compelling banks to submit rates for the calculation of LIBOR after 2021.
Added
In particular, the U.S. government’s recent imposition of tariffs on all imported steel may increase the cost of materials and equipment essential to our drilling operations. These higher costs could negatively impact our capital expenditures and the overall economics of our projects.
Removed
In March 2021, ICE Benchmark Administration, the administrator for LIBOR, ceased publishing United States Dollar LIBOR (“USD LIBOR”) for one week and two-month tenors after December 31, 2021, and confirmed its intention to cease all remaining USD LIBOR tenors after June 30, 2023.
Added
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.
Removed
Concurrently, the United Kingdom Financial Conduct Authority announced the cessation or loss of representativeness of the USD LIBOR tenors from those dates.
Added
In particular, cash flow from operations were $73.9 million and $115.6 million for the years ended December 31, 2024 and 2023, respectively.
Removed
The Alternative Reference Rates Committee, a group of market participants convened by the United States Federal Reserve Board and the Federal Reserve Bank of New York, has recommended the Secured Overnight Financing Rate (“SOFR”), a rate calculated based on repurchase agreements backed by United States Treasury securities, as its recommended alternative benchmark rate to replace USD LIBOR.
Added
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. Under the EPAct 2005 and implementing regulations, the FERC prohibits market manipulation in connection with the purchase or sale of natural gas.
Removed
At this time, it is not known whether or when SOFR or other alternative reference rates will attain market traction as replacements for LIBOR. These reforms may cause LIBOR to perform differently than it has in the past, and LIBOR will cease to exist after June 30, 2023.
Added
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.
Removed
After the cessation of LIBOR, alternative benchmark rates will replace LIBOR and could affect our debt securities, debt payments and receipts. At this time, it is not possible to predict the effect of any changes to LIBOR, any phase out of LIBOR or any establishment of alternative benchmark rates.
Added
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.
Removed
Any new benchmark rate will likely not replicate LIBOR exactly, which could impact our contracts that terminate after June 30, 2023. There is uncertainty about how applicable law and the courts will address the replacement of LIBOR with alternative rates on variable rate retail loan contracts and other contracts that do not include alternative rate fallback provisions.
Added
A cybersecurity incident of this nature would be outside our control, but could have a material, adverse effect on our business, financial condition and results of operations.
Removed
In addition, any changes to benchmark rates may have an uncertain impact on our cost of funds and our access to the capital markets, which could impact our results of operations and cash flows.
Added
A decrease in enacted corporate tax rates in our major jurisdictions, especially the U.S. federal corporate rate, would decrease the value of our deferred tax assets, which could be material. Risks Relating to Our Common Stock We have adopted a Tax Benefits Preservation Plan, which may discourage a corporate takeover.
Removed
Uncertainty as to the nature of such potential changes may also adversely affect the trading market for our securities.The full effects of the transition away from LIBOR remain uncertain.
Removed
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.
Removed
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.
Removed
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.
Removed
The Company will submit this amendment to the Company’s stockholders for approval at our 2024 Annual Meeting.
Removed
The Company will submit this amendment to the Company’s stockholders for approval at our 2024 Annual Meeting. Each share of our common stock issued thereafter will also include one right.
Removed
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.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

1 edited+1 added−0 removed17 unchanged
Biggest changeThe following is a brief list of some of the cybersecurity risk management tools we employ to identify, assess and manage threat risks: – Third party system and network scanning tools that identify or automatically block potential cybersecurity threats; – Live 24-hour monitoring of corporate and field operations IT networks for cybersecurity threats; – Mandatory annual employee cybersecurity awareness training program that includes phishing simulations and other microlearning courses; – Monthly IT and cybersecurity meetings with management and IT professionals; – Completion of annual IT network cybersecurity assessment and vulnerability scan; – Segregation of our financial data records, that are stored on remote servers, separate and apart from our corporate office network with backups stored in different geographical regions in the United States.
Biggest changeThe following is a brief list of some of the cybersecurity risk management tools we employ to identify, assess and manage threat risks: – Third party system and network scanning tools that identify or automatically block potential cybersecurity threats; – Routine review and update of system access; – Multi-factor authentication; – Live 24-hour monitoring of corporate and field operations IT networks for cybersecurity threats; – Mandatory annual employee cybersecurity awareness training program that includes phishing simulations and other microlearning courses; – Monthly IT and cybersecurity meetings with management and IT professionals; – Completion of annual IT network cybersecurity assessment and vulnerability scan; – Segregation of our financial data records, that are stored on remote servers, separate and apart from our corporate office network with backups stored in different geographical regions in the United States.
Added
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.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

5 edited+2 added−4 removed2 unchanged
Biggest changeIn addition to the quarterly dividend payments, the Company paid $0.3 million in cash dividends on vested stock awards during the year ended December 31, 2023. Dividend payments for the year ended December 31, 2023 total $81.5 million. See Note 19 for discussion on dividends declaredpaid in 2024.
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.
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 1, 2024, there were 313 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 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.
The maximum number of shares that may still be purchased under the buyback program as of March 1, 2024 is approximately 5.8 million.
The maximum number of shares that may still be purchased under the buyback program as of March 4, 2025 is approximately 6.7 million.
Dividends In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023. The aggregate total payout was $73.8 million.
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.
In August 2023, the Board declared a cash dividend of $0.10 per share of the Company’s common stock, which was paid on August 28, 2023 to shareholders of record as of the close of business on August 14, 2023. The aggregate total payout was $3.7 million.
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.
Removed
Additionally, in May 2023, the Board announced plans for a regular quarterly dividend of $0.10 per share, subject to quarterly approval by the Board.
Added
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.
Removed
On November 2, 2023, the Board declared a cash dividend of $0.10 per share of the Company’s common stock, which was paid on November 27, 2023 to shareholders of record as of the close of business on November 13, 2023. The aggregate total payout was $3.7 million.
Added
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.
Removed
The payment of any dividends in the future, and the timing and amount thereof, is within the discretion of our Board of Directors.
Removed
Issuer Purchases of Equity Securities There were no issuer purchases of equity securities during the quarter ended December 31, 2023. In May 2023, the Board approved a stock buyback program authorizing the repurchase of up to $75 million of the Company's outstanding common stock in open market transactions with no expiration date.

Item 7. Management's Discussion & Analysis

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

55 edited+12 added−17 removed31 unchanged
Biggest changeOur capital expenditures for the years ended December 31, 2023 and 2022, are summarized below (in thousands): Year Ended December 31, 2023 2022 Capital Expenditures Drilling and completions $ 18,132 $ 38,077 Capital workovers 4,346 10,322 Leasehold and geophysical (46) 809 Capital expenditures, excluding acquisitions (on an accrual basis) 22,432 49,208 Acquisitions 11,232 1,431 Capital expenditures, including acquisitions 33,664 50,639 Changes in accounts payable and accrued expenses 5,232 (5,123) Inventory material transfers to oil and natural gas properties $ (1,289) $ — Total cash paid for capital expenditures, including acquisitions $ 37,607 $ 45,516 Capital expenditures, excluding acquisitions, for development activities decreased for the year ended December 31, 2023 compared to 2022, primarily due to the conclusion of our drilling program in the second quarter of 2023.
Biggest changeOur 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 Financing Activities 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 $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.
However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as additional declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves.
However, a full cost ceiling limitation impairment may still be realized in the future based on the outcome of numerous other factors such as declines in the actual trailing twelve-month SEC prices, production, lower commodity prices, changes in estimated future development costs and operating expenses, and other revisions to our proved reserves.
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, 2023 and 2022.
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.
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, 2023 and 2022.
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.
These estimates and assumptions can be inherently unpredictable and may differ from actual results given the uncertainty of when we may be required to plug and abandon a well or retire an asset. As a result, we may not incur all of the estimated costs for the current asset retirement obligation as depicted above.
These estimates and assumptions can be inherently unpredictable and may differ from actual results given the uncertainty of when we may be required to plug and abandon a well or retire an asset. As a result, we may not incur all or may incur more than the estimated costs for the current asset retirement obligation as depicted above.
Highlighted Events • 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.
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.
We did not record a full cost ceiling limitation impairment for the years ended December 31, 2023 or 2022. 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 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.
Applying these estimated first quarter prices, and holding all other inputs constant to those used in the calculation of our December 31, 2023 ceiling test, no full cost ceiling limitation impairment is indicated for the first quarter of 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.
For the comparison of the years ended December 31, 2022 and 2021, see “Management's Discussion and Analysis of Consolidated Results of Operations” in Part II, Item 7 of our 2022 Annual Report on Form 10-K, filed with the Securities and Exchange Commission on March 15, 2023.
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.
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, 2023 or 2022. 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, 2024 or 2023. 54 Table of Contents Asset Retirement Obligations.
Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award, t hat equals the employee payroll tax obligation due.
Net exercises of stock awards allows the holder of a stock award to tender back to us a number of shares at fair value upon the vesting of such stock award, that equals the employee payroll tax obligation due.
During the year ended December 31, 2023, plugging and abandonment costs incurred were $0.9 million. 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, 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.
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, 2023 2022 NYMEX WTI Oil (per Bbl) $ 77.58 $ 94.90 NYMEX Henry Hub Natural gas (per Mcf) $ 2.63 $ 6.68 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, 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.
Revenues Consolidated revenues for the years ended December 31, 2023 and 2022 are presented in the table below (in thousands).
Revenues Consolidated revenues for the years ended December 31, 2024 and 2023 are presented in the table below (in thousands).
The following table summarizes derivative activity for the years ended December 31, 2023 and 2022 (in thousands): Year Ended December 31, 2023 2022 (Gain) loss on derivative contracts $ (1,447) $ (5,975) Realized settlement gains (losses) on derivative contracts $ 5,876 $ 1,525 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 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.
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 1, 2024 , the Company had no outstanding term or revolving debt obligations.
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.
The average rates used for depreciation and depletion of oil and natural gas properties were $1.82 per Boe in 2023 and $1.18 per Boe in 2022. Impairment of Oil and Natural Gas Properties. In accordance with full cost accounting rules, capitalized costs are subject to a limitation.
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.
For example, during the period from January 2019 through December 2023, 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 $1.38 per Mcf.
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.
Based on the SEC prices over the eleven months ended February 1, 2024 and NYMEX strip pricing for March 2024 as of March 1, 2024, we anticipate the SEC prices utilized in the March 31, 2024 full cost ceiling test may be $77.48 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, 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").
As of December 31, 2023, we had future contractual commitments under various agreements, which are summarized below. The short-term leases and operating lease are not recorded in the accompanying consolidated balance sheets.
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.
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, 2023, there were two operated wells drilled and four 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 For the year ended December 31, 2024, there were no operated wells drilled, with three operated and one non-operated wells completed.
Working Capital and Sources and Uses of Cash Our principal sources of liquidity for 2024 include cash flow from operations and cash on hand. Our working capital decreased to $228.5 million at December 31, 2023, compared to $241.6 million at December 31, 2022.
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.
Any such ceiling test impairments in 2024 could be material to our net earnings.
Any such ceiling test impairments in the future could be material to our net earnings.
Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized. Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns.
Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards. Deferred tax assets are reduced by a valuation allowance if it is deemed more likely than not that some or all of the deferred tax assets will not be realized.
When excluding the effects of pricing, 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, 2023 were less than 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, 2024 were approximately 3%.
“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, 2023 and 2022 consisted of the following (in thousands): Year Ended December 31, 2023 2022 Interest income (expense), net Interest income $ 10,656 $ 2,026 Interest expense Interest expense on letters of credit $ (37) $ (37) Interest expense on right of use assets (64) (36) Interest expense - other (3) (143) Total interest expense (104) (216) Total interest income (expense), net $ 10,552 $ 1,810 Interest (income) expense, net during the year ended December 31, 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. 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.
The SEC prices utilized in the calculation of proved reserves included in the full cost ceiling test at December 31, 2023 were $78.22 per barrel of oil and $2.64 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, 2024 were $75.48 per barrel of oil and $2.13 per MMBtu of natural gas, before price differential adjustments.
See “Consolidated Results of Operations” for further analysis of the changes in revenues and operating expenses. 51 Table of Contents Cash Flows from Investing Activities 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.
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.
Approximately 95.2% of the Company’s reserves were estimated by independent petroleum engineers as of December 31, 2023. Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Estimates of proved reserves are based on the quantities of oil, natural gas and NGLs that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions.
Our partial valuation release of $64.5 million as of December 31, 2022 was partially offset by $14.0 million due to changes in expected future income, resulting in net deferred tax assets of $50.6 million as of December 31, 2023. We anticipate being able to utilize these deferred tax assets based on the generation of future income.
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.
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.
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.
As the partial valuation allowance release as of December 31, 2023 was lower than the partial valuation allowance release as of December 31, 2022 of $64.5 million, we recognized $14.0 million of deferred federal and state income tax expense for the year ended December 31, 2023. 50 Table of Contents Liquidity and Capital Resources At December 31, 2023, our cash and cash equivalents, including restricted cash, was $253.9 million.
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.
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, 2023 and 2022 consisted of the following (in thousands): Year Ended December 31, 2023 2022 Change General and administrative $ 10,735 $ 9,449 $ 1,286 Restructuring expenses 406 382 24 Employee termination benefits 19 — 19 (Gain) loss on derivative contracts (1,447) (5,975) 4,528 Other operating expense (income) (157) (99) (58) Total other operating expenses $ 9,556 $ 3,757 $ 5,799 General and administrative expenses increased for the year ended December 31, 2023 primarily due to higher technology, service and personnel costs.
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.
Cash flows for the years ended December 31, 2023, and 2022 are presented in the following table and discussed below (in thousands): Year Ended December 31, 2023 2022 Cash flows provided by operating activities $ 115,578 $ 164,696 Cash flows used in investing activities (36,164) (45,117) Cash flows used in financing activities (82,938) (1,635) Net (decrease) increase in cash, cash equivalents and restricted cash $ (3,524) $ 117,944 Cash Flows from Operating Activities The $49.1 million decrease in operating cash flows for the year ended December 31, 2023 compared to 2022, is primarily due to a decrease in revenues from lower commodity prices.
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.
The Company did not repurchase any common stock under the existing or prior Program during the years ended December 31, 2023 and 2022. 52 Table of Contents Contractual Obligations and Off-Balance Sheet Arrangements At December 31, 2023, our contractual obligations included asset retirement obligations and short and long-term leases.
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.
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. 53 Table of Contents Proved Reserves.
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.
Income tax (benefit) We recorded income tax expense and benefit of $14.0 million and $64.5 million for the years ended December 31, 2023 and 2022, respectively, which directly relates to our partial valuation allowance release.
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.
Year Ended December 31, 2023 2022 Change Production data (in thousands) Oil (MBbls) 1,047 949 98 Natural gas (MMcf) 20,403 21,101 (698) NGL (MBbls) 1,705 1,997 (292) Total volumes (MBoe) 6,152 6,463 (311) Average daily total volumes (MBoe/d) 16.9 17.7 (0.8) Average prices—as reported (1) Oil (per Bbl) $ 74.69 $ 92.21 $ (17.52) Natural gas (per Mcf) $ 1.71 $ 4.88 $ (3.17) NGL (per Bbl) $ 20.83 $ 31.88 $ (11.05) Total (per Boe) $ 24.16 $ 39.34 $ (15.18) Average prices—including impact of derivative contract settlements Oil (per Bbl) $ 74.69 $ 92.21 $ (17.52) Natural gas (per Mcf) $ 2.00 $ 4.97 $ (2.97) NGL (per Bbl) $ 20.83 $ 31.72 $ (10.89) Total (per Boe) $ 25.11 $ 39.58 $ (14.47) ___________________ (1) Prices represent actual average prices for the periods presented and do not include the impact of derivative transactions.
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.
See "Note 3 — Acquisitions and Divestitures 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.
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.
Year Ended December 31, 2023 2022 Change Revenues Oil $ 78,174 $ 87,528 $ (9,354) Natural gas 34,941 103,067 (68,126) NGL 35,526 63,663 (28,137) Total revenues $ 148,641 $ 254,258 $ (105,617) 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, 2023 and 2022 are shown in the table below (in thousands): 2022 oil, natural gas and NGL revenues $ 254,258 Change due to production volumes in 2023 (7,514) Change due to average prices in 2023 (98,103) 2023 oil, natural gas and NGL revenues $ 148,641 47 Table of Contents Oil, natural gas and NGL revenues decreased primarily due to lower commodity prices.
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.
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) $ 64,404 $ 9,851 $ — $ — $ 54,553 Operating lease 167 167 — — — Short-term leases 1,773 1,773 — — — Finance lease 1,311 616 695 — — Total $ 67,655 $ 12,407 $ 695 $ — $ 54,553 ____________________ (1) Asset retirement obligations are based on estimates and assumptions that affect the reported amounts as of December 31, 2023.
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.
In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized. The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized.
Deferred tax liabilities are recognized for temporary differences that will be taxable in future years’ tax returns. In assessing the realizability of the deferred tax assets, we consider whether it is more likely than not that some or all of the deferred tax assets will not be realized.
Total special and regular dividends for the year ended December 31, 2023 were $81.5 million. See Note 13 for further discussion of the Company’s dividends. 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.
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.
During the year ended December 31, 2022, cash flows used in investing activities primarily reflects capital expenditures of $44.1 million related to drilling and completions, capital workovers, well reactivations, and inventory purchases and $1.4 million related to an acquisition of proved reserves. Cash outflows were partially offset by $0.4 million of proceeds from the sale of assets.
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.
Dividend payments to shareholders of $81.5 million, $26.4 million in capital expenditures, and $11.2 million related to an acquisition of proved reserves were the primary drivers in the reduction of working capital. These cash outflows were offset by $115.6 million in cash provided by operating activities.
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.
Operating Expenses Operating expenses for the years ended December 31, 2023 and 2022 consisted of the following (in thousands): Year Ended December 31, 2023 2022 Change Lease operating expenses $ 41,862 $ 41,286 $ 576 Production, ad valorem, and other taxes 10,870 15,880 (5,010) Depreciation and depletion—oil and natural gas 15,657 11,542 4,115 Depreciation and amortization—other 6,518 6,342 176 Total operating expenses $ 74,907 $ 75,050 $ (143) Lease operating expenses ($/Boe) $ 6.80 $ 6.39 $ 0.41 Production, ad valorem, and other taxes ($/Boe) $ 1.77 $ 2.46 $ (0.69) Depreciation and amortization—oil and natural gas ($/Boe) $ 2.54 $ 1.79 $ 0.75 Production, ad valorem, and other taxes (% of oil, natural gas, and NGL revenue) 7.3 % 6.2 % 1.1 % The increase in lease operating expenses was primarily due to inflationary pressures and higher production costs associated with more producing wells from our prior well reactivations and development program as well as increased ownership interest from our July 2023 acquisition during the year ended December 31, 2023.
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.
Production, ad valorem, and other taxes decreased primarily due to lower commodity prices and related revenues.
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.
The increase in depreciation and depletion for oil and natural gas properties was primarily the result of capital expenditures for 2023 and a decrease in proved reserves at December 31, 2023, primarily as a result of lower SEC prices (as defined below), which increased our depletion rate. Full cost pool impairment.
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.
Restructuring expenses represent fees and costs associated with our predecessor company's 2016 bankruptcy filing and our exit from NPB in Colorado.
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.
We will continue to monitor forward-looking commodity prices, results, costs and other factors that could influence returns on investments, which will continue to shape our disciplined development decisions in 2024 and beyond.
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.
These projects include (1) artificial lift conversions to more efficient and cost effective systems, (2) high-graded re-fracturing and recompletion and (3) limited opportunistic leasing in proven areas around or adjacent to our area of operations that could further bolster future development.
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.
Additionally, in May 2023, the Board announced plans for a regular quarterly dividend of $0.10 per share, subject to quarterly approval by the Board. The Company paid quarterly dividends of $3.7 million each on August 28, 2023 and November 27, 2023, totaling $7.4 million, as well as dividends on vested stock awards of $0.3 million for the year.
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.
Deferred income taxes are recorded for temporary differences between the financial statement and income tax basis of assets and liabilities. Deferred tax assets are recognized for temporary differences that will be deductible in future years’ tax returns and for operating loss and tax credit carryforwards.
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 charts below show production and percent revenues by product for the years ended December 31, 2023 and 2022: 44 Table of Contents Total production for the years ended December 31, 2023 and 2022 was composed of the following: Year Ended December 31, 2023 2022 Oil 17.0 % 14.7 % Natural gas 55.3 % 54.4 % NGL 27.7 % 30.9 % Total 100.0 % 100.0 % The increase in oil production was primarily driven by the newly drilled wells as part of our capital development program.
Production 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.
Removed
For the year ended December 31, 2022 there were eight operated wells drilled, six wells completed, and 50 wells reactivated.
Added
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.
Removed
The decrease in total MBoe was primarily driven by a reduction of NGL production, as one of our purchasers elected to retain more ethane in the natural gas stream, which had more favorable market pricing at the time of sales, as well as natural decline of its producing assets.
Added
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.
Removed
These factors were partially offset by production added during the third quarter from an acquisition that closed on July 11, 2023, which increased our ownership interest in twenty-six wells we operate.
Added
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.
Removed
Additionally, in January 2024, the Board announced that it plans to increase its on-going quarterly dividend to $0.11 per share starting with the next quarterly payout, estimated to be first paid in March 2024, continuing every quarter thereafter until noticed, subject to quarterly approval by the Board. • On July 11, 2023, the Company closed an acquisition that increased its ownership interest in twenty-six producing wells operated by the Company within the Northwest Stack play for $10.6 million, after customary post-closing adjustments, with an effective date of April 1, 2023.
Added
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.
Removed
The Company used its cash on hand to fund the acquisition. • In May 2023, the Board approved a one-time cash dividend of $2.00 per share of the Company’s common stock, which was paid on June 7, 2023 to shareholders of record as of the close of business on May 24, 2023.
Added
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.
Removed
Additionally, in May 2023, the Board announced a regular quarterly dividend of $0.10 per share of the Company’s common stock, subject to quarterly approval by the Board.
Added
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.
Removed
Our dividend payment in May was $73.8 million and the $0.10 dividend payments made in August 2023 and November 2023 totaled $7.4 million. • In May 2023, the Board approved a stock buyback program authorizing the repurchase of up to $75 million of the Company’s outstanding common stock in open market transactions. 45 Table of Contents Outlook We will continue to focus on growing the value and cash generation capability of our asset base in a safe, responsible and efficient manner, while exercising prudent capital allocations to projects we believe provide high rates of returns in the current commodity price environment.
Added
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.
Removed
While commodity price futures are not yet at preferred levels to resume drilling or further well reactivations at this time, we retain the development option over a reasonable tenor, since our assets are 99% held by production.
Added
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
We will also continue to maintain optionality to execute on value accretive merger and acquisition opportunities that could bring synergies, leverage our core competencies, compliment our portfolio of assets, further utilize our NOLs or otherwise yield attractive returns for our shareholders.
Added
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.
Removed
Production volumes for the year ended December 31, 2023 decreased slightly due to the natural declines of our producing wells, which were partially offset from the production from our new wells and increased ownership interest from our July 2023 acquisition.
Added
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.
Removed
However, production, ad valorem, and other taxes increased as a percentage of oil, natural gas and NGL revenue primarily due to higher oil and gas property valuation assessments by local jurisdictions who use historical commodity price averages that included prior periods that were higher than current commodity prices, when determining ad valorem tax assessments.
Added
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.
Removed
Interest (income) expense, net during the year ended December 31, 2022 is primarily comprised of interest income received from cash deposits partially offset by interest paid on royalty obligations of $0.1 million, interest on vehicle leases and letters of credit.
Added
The ultimate realization of the deferred tax assets is dependent upon the generation of future income in periods in which the deferred tax assets can be utilized.
Removed
Other income (expense), net The Other income (expense), net line item was not significant for the year ended December 31, 2023. For the year ended December 31, 2022, Other income (expense), net of $0.4 million is primarily comprised of gains on the sale of fleet vehicles and the removal of previously accrued liabilities due to a change in estimate.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeBecause 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. As a result, and when applicable, current period earnings could have been significantly affected by changes in the fair value of our commodity derivative contracts.
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.
We are also exposed to credit risk related to the collection of receivables from our joint interest partners for their proportionate share of expenditures on wells and properties we operate. Historically, our credit losses on joint interest receivables have been immaterial. 56 Table of Contents
We are also exposed to credit risk related to the collection of receivables from our joint interest partners for their proportionate share of expenditures on wells and properties we operate. Historically, our credit losses on joint interest receivables have been immaterial.
The following table summarizes derivative activity for the years ended December 31, 2023 and 2022 (in thousands): Year Ended December 31, 2023 2022 (Gain) loss on derivative contracts $ (1,447) $ (5,975) Realized settlement gains (losses) on derivative contracts $ 5,876 $ 1,525 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 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.
Our derivative contracts have historically been with multiple counterparties to minimize exposure to any individual counterparty, and in addition our counterparties have been large financial institutions. We did not require collateral or other security from counterparties to support derivative instruments.
Our derivative contracts have historically been with multiple counterparties to minimize exposure to any individual counterparty, and in addition our counterparties have been large financial institutions. 56 Table of Contents We did not require collateral or other security from counterparties to support derivative instruments.
We have used, and may use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and collars. At December 31, 2023, we had no open commodity derivative contracts or obligations to enter into commodity derivative contracts.
We have used, and may use, a variety of commodity-based derivative contracts, including fixed price swaps, basis swaps and producer costless collars.
Changes in fair value were principally measured based on a comparison of future prices to the contract price at the end of the period.
As a result, and when applicable, current period earnings could have been significantly affected by changes in the fair value of our commodity derivative contracts. Changes in fair value were principally measured based on a comparison of future prices to the contract price at the end of the period.

Other SD 10-K year-over-year comparisons