10q10k10q10k.net

What changed in RING ENERGY, INC.'s 10-K — 2024 vs 2025

vs

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

+342 added−348 removedSource: 10-K (2026-03-04) vs 10-K (2025-03-05)

Top changes in RING ENERGY, INC.'s 2025 10-K

342 paragraphs added · 348 removed · 255 edited across 8 sections

Item 1. Business

Business — how the company describes what it does

44 edited+18 added−28 removed109 unchanged
Biggest changeWe believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations. 2024 Highlights and Major Developments • Achieved record full year production of 19,648 Boepd (68% oil), a year-over-year increase in total Boe of 9% • Executed a phased drilling program in 2024 that included drilling 44.00 gross / 43.94 net operated wells consisting of 22.00 horizontal and 22.00 vertical wells (gross). • Maintained our revolving credit facility borrowing base of $600 million • Total proved reserves were 134.2 MMBoe at year-end 2024, which increased 4.4 MMBoe, or 3% from year-end 2023.
Biggest changeWe believe our core leasehold in the Northwest Shelf and Central Basin Platform contain additional potential drilling locations. 2025 Highlights and Major Developments • Closed the Lime Rock Acquisition on March 31, 2025. • Achieved record full year production of 20,253 Boepd (65% oil), a year-over-year increase in total Boe of 3%. • Lowered lifting costs to $10.73 per Boe, or 1% year over year including 9 months of the LRR acquisition assets. • Responded to lower commodity price environment by pulling back on capital expenditures, executing a phased drilling program in 2025 that included drilling 18 gross, 17 net operated wells consisting of 12 horizontal and six vertical wells (gross). • Total proved reserves were 153.3 MMBoe at year-end 2025, which increased 19.1 MMBoe, or 14% from year-end 2024.
Generally, these laws (i) regulate air and water quality, impose limitations on 12 Table of Contents the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) require remedial measures to mitigate pollution from former or ongoing operations; and (iv) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws.
Generally, these laws (i) regulate air and water quality, impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) require remedial measures to mitigate pollution from former or ongoing operations; and (iv) may result in the assessment of administrative, civil and criminal penalties for 12 Table of Contents failure to comply with such laws.
Key principles supporting Ring’s strategic vision are to: • Ensure health, safety, and environmental excellence with a strong commitment to Ring’s employees and the communities in which we work and operate; • Continue our focus on generating adjusted free cash flow to improve and build a sustainable financial foundation; • Pursue rigorous capital discipline focused on Ring’s highest returning opportunities; • Improve margins and drive value by targeting additional operating cost reductions and capital efficiencies; and • Strengthen our balance sheet by paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.
Key principles supporting Ring’s strategic vision are to: • Ensure health, safety, and environmental excellence with a strong commitment to Ring’s employees and the communities in which we work and operate; • Continue our focus on generating adjusted free cash flow to improve and build a sustainable financial foundation; • Pursue rigorous capital discipline focused on Ring’s highest returning opportunities; • Improve margins and drive value by targeting additional operating cost reductions and capital efficiencies; and 8 Table of Contents • Strengthen our balance sheet by paying down debt, divesting of non-core assets and becoming a peer leader in Debt/EBITDA metrics.
Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events, such events could have a material adverse 17 Table of Contents effect on the Company and potentially subject the Company to further regulation.
Finally, to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, and other climatic events, such events could have a material adverse effect on the Company and potentially subject the Company to further regulation.
To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intra-facility 14 Table of Contents piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution.
To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intra-facility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution.
The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.
The information on, or that can be accessed through, our website is not incorporated by reference into this Annual Report and should not be considered part of this Annual Report. The SEC also maintains a website (http://www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC. 19 Table of Contents
Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. Regulation of Transportation of Oil Sales of crude oil, natural gas, and NGLs are not currently regulated and are made at negotiated prices; however, Congress could reenact price controls in the future.
Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations. 11 Table of Contents Regulation of Transportation of Oil Sales of crude oil, natural gas, and NGLs are not currently regulated and are made at negotiated prices; however, Congress could reenact price controls in the future.
Where applicable, we maintain and implement SPCC plans for our facilities. Water Discharges The CWA and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into navigable waters, defined as waters of the United States (“WOTUS”), as well as state waters.
Where applicable, we maintain and implement SPCC plans for our facilities. 14 Table of Contents Water Discharges The CWA and analogous state laws and regulations impose restrictions and strict controls regarding the discharge of pollutants into navigable waters, defined as waters of the United States (“WOTUS”), as well as state waters.
Consequently, state regulators implementing both the federal UIC program and state corollaries have been heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection. 15 Table of Contents In Texas, the RRC regulates the disposal of produced water by injection well.
Consequently, state regulators implementing both the federal UIC program and state corollaries have been heavily scrutinizing the location of injection facilities relative to faulting and are limiting both the density and injection facilities as well as the rate of injection. In Texas, the RRC regulates the disposal of produced water by injection well.
The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, can affect our profitability. Regulation of Drilling and Production The production of oil and natural gas is subject to regulation under a wide range of local, state, and federal statutes, rules, orders, and regulations.
The regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability. Regulation of Drilling and Production The production of oil and natural gas is subject to regulation under a wide range of local, state, and federal statutes, rules, orders, and regulations.
Our Mission Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural gas resources that are vital to the world’s health and welfare. 8 Table of Contents Our Key Principles Successfully achieving Ring’s mission requires a firm commitment to operating safely in a socially responsible and environmentally friendly manner.
Our Mission Ring’s mission is to deliver competitive and sustainable returns to its shareholders by developing, acquiring, exploring for, and commercializing oil and natural gas resources that are vital to the world’s health and welfare. Our Key Principles Successfully achieving Ring’s mission requires a firm commitment to operating safely in a socially responsible and environmentally friendly manner.
Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdictions. 11 Table of Contents The failure to comply with these rules and regulations can result in substantial penalties.
Moreover, Texas imposes a production or severance tax with respect to the production and sale of oil, natural gas, and NGLs within its jurisdictions. The failure to comply with these rules and regulations can result in substantial penalties.
Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
Among other things, the 15 Table of Contents rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
Refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Drilling and Completion, for details of our 2024 operations.
Refer to Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations, Drilling and Completion, for details of our 2025 operations.
If we are required to meet "best available control technology," our operations could be adversely affected and our ability to obtain air permits for new or modified facilities that exceed GHG emission thresholds could be restricted or delayed.
If we are required to meet "best available control technology," our operations could be adversely affected and our ability to obtain air 16 Table of Contents permits for new or modified facilities that exceed GHG emission thresholds could be restricted or delayed.
Federal, state, and local statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Until recently, the trend in oil and natural gas regulation was to increase regulatory restrictions and limitations on such activities.
These statutes and regulations require permits for drilling operations, drilling bonds, and reports concerning operations. Until recently, the trend in oil and natural gas regulation was to increase regulatory restrictions and limitations on such activities.
The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency pursuant to Section 404 of the CWA.
The CWA prohibits the placement of dredge or fill material in wetlands or other WOTUS unless authorized by a permit issued by the U.S. Army Corps of Engineers (“Corps”) or a delegated state agency.
The State of Texas has filed suit challenging the listing. The dunes sagebrush lizard is found in portions of Texas, including areas where we operate. The listing of the dunes sagebrush lizard as an endangered species, may impact our operations in any area that is designated as the dunes sagebrush lizard’s habitat.
The dunes sagebrush lizard is found in portions of Texas, including areas where we operate. The listing of the dunes sagebrush lizard as an endangered species, may impact our operations in any area that is designated as the dunes sagebrush lizard’s habitat.
Ring Energy’s Strengths Our strengths include: 9 Table of Contents • High quality asset base in one of North America’s leading oil and gas producing regions characterized by relatively low declines and attractive margins; • De-risked Permian Basin acreage position with multi-year drilling inventory of horizontal and vertical development potential; • Concentrated acreage position with high degree of operational control; • Experienced and proven management team with substantive technical and operational expertise; • Operating control over most of our production and development activities; and • Commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in which we work and operate.
Ring Energy’s Strengths Our strengths include: • High quality asset base in one of North America’s leading oil and gas producing regions characterized by relatively low declines and attractive margins; • De-risked Permian Basin acreage position with multi-year drilling inventory of horizontal and vertical development potential; • Concentrated acreage position with high degree of operational control; • Experienced and proven management team with substantive technical and operational expertise; • Operating control over most of our production and development activities; and • Commitment to cost efficient operations, health, safety, protecting the environment, our employees, and the communities in which we work and operate. 9 Table of Contents Competitive Business Conditions We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas, and securing competent personnel.
To the extent any action expands the scope of the CWA in areas where we or our suppliers, customers or service providers operate or imposes new or enhanced permitting requirements, our operations could be adversely impacted by increased compliance costs and energy infrastructure project delays or cancellations.
NWP 12 is expected to be reissued by the Corps in 2026. To the extent any action expands the scope of the CWA in areas where we or our suppliers, customers or service providers operate or imposes new or enhanced permitting requirements, our operations could be adversely impacted by increased compliance costs and energy infrastructure project delays or cancellations.
The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant 16 Table of Contents Deterioration (“PSD”) construction and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.
The EPA has adopted and implemented regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) pre-construction permits, and Title V operating permits for GHG emissions from certain large stationary sources that already are major sources of criteria pollutants under the CAA.
As of December 31, 2024, we had 115 full-time employees. Our employees are extremely valuable to the success of the Company, and we encourage their collaboration and respect their diverse points of view and opinions.
As of December 31, 2025, we had 111 full-time employees. Our employees are extremely valuable to the success of the Company, and we encourage their collaboration and respect their points of view and opinions.
Proved reserves as of December 31, 2024 (based upon the report of our independent petroleum engineer of that date) were approximately 134.2 million Boe, of which we are the operator of approximately 99%.
Proved reserves as of December 31, 2025 (based upon the report of our independent petroleum engineer of that date) were approximately 153.3 million Boe, of which we are the operator of approximately 99%.
If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state, or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs.
The rules also update requirements on the design, construction, operation, monitoring, and closure of waste management units If new laws or regulations that significantly restrict hydraulic fracturing are adopted at the local, state, or federal level, our fracturing activities could become subject to additional permit and financial assurance requirements, more stringent construction requirements, increased reporting or plugging and abandoning requirements or operational restrictions and associated permitting delays and potential increases in costs.
For the year ended December 31, 2024, sales to three customers represented 88% of our oil, natural gas, and natural gas liquids revenues. As of December 31, 2024, accounts receivable from these three customers represented 86% of our total accounts receivable. Refer to the table below for the details of these percentages, respectively.
For the year ended December 31, 2025, sales to three customers represented 89% of our oil, natural gas, and NGL revenues. As of December 31, 2025, accounts receivable from these three customers represented 82% of our total accounts receivable. Refer to the table below for the details of these percentages, respectively.
All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 60% consisting of oil, 19% consisting of natural gas, and 21% consisting of NGLs. Approximately 69% of the reserves are classified as PD and 31% are classified as PUD.
All of our properties are located in the Permian Basin and our proved reserves are oil-weighted, with approximately 59% consisting of oil, 19% consisting of natural gas, and 22% consisting of NGLs. Approximately 68% of the reserves are classified as PD and 32% are classified as PUD.
In addition to our full-time employees, the Company also employs a diverse group of independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed. None are represented by labor unions or covered by any collective bargaining agreements.
In addition to our full-time employees, the Company also employs independent contractors who assist our full-time staff in a range of areas including geology, engineering, land, accounting, and field operations, as needed. None are represented by labor unions or covered by any collective bargaining agreements. We recognize that attracting, retaining and developing our employees is critical for our future success.
Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas. As of December 31, 2024, our leasehold acreage positions totaled 97,599 gross (80,919 net) acres and we held interests in 935 gross (763 net) producing wells.
Our drilling operations target the oil and liquids rich producing formations in the Northwest Shelf and the Central Basin Platform, in the Permian Basin in Texas. As of December 31, 2025, our leasehold acreage positions totaled 111,714 gross (96,234 net) acres and we held interests in 919 gross (758 net) producing wells.
Within the PD reserve category, 220 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 211 proved locations (27% horizontal and 73% vertical) based on the reserve report as of December 31, 2024.
Within the PD reserve category, 238 recompletion and re-activation opportunities are classified as PDNP and within the PUD reserve category, we have a total of 247 proved locations (38% horizontal and 62% vertical) based on the reserve report as of December 31, 2025.
Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations.
Some of our key human capital areas of focus include the following. Building a Safe Workforce Starts with Our Culture: Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop a job, without retribution, if conditions are deemed unsafe.
Building a Safe Workforce Starts with Our Culture: Ring is committed to building a safety culture that empowers employees and contractors to act as needed to work safely and to stop a job, without retribution, if conditions are deemed unsafe. We strive to be incident-free every day across our operations.
These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the CWA. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The dunes sagebrush lizard is one example of a species that was recently listed as an endangered species.
Pursuant to the ESA, if a species is listed as threatened 17 Table of Contents or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. The dunes sagebrush lizard is one example of a species that was recently listed as an endangered species. The State of Texas has filed suit challenging the listing.
For the Year Ended As of December 31, 2024 December 31, 2024 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues Percentage of accounts receivables from the sale of our Oil, Natural Gas and NGL production Customer: Phillips 66 Company ("Phillips") 61% 64% Concord Energy LLC ("Concord") 14% 11% LPC Crude III, LLC ("LPC") 13% 11% Total of top three customers 88% 86% Delivery Commitments As of December 31, 2024, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.
We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas. 10 Table of Contents For the year ended As of December 31, 2025 December 31, 2025 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues Percentage of accounts receivables from the sale of our Oil, Natural Gas and NGL production Customer: Phillips 66 Company ("Phillips") 67% 66% Concord Energy LLC ("Concord") 13% 10% NGL Crude Partners ("NGL Crude") 9% 6% Total of top three customers 89% 82% Delivery Commitments As of December 31, 2025, we were not committed to providing a fixed quantity of oil or natural gas under any existing contracts.
The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations.
The RRC adopted rules that allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations. In December 2024, the RRC adopted a significant overhaul of its rules regulating oil and natural gas waste management facilities in Texas.
We strive to be incident-free every day across our operations. We are focused on building and maintaining a safe workplace for all employees and contractors. The oil and gas industry has a number of inherent risks and our workers are often outdoors, in all seasons and all types of weather.
We are focused on building and maintaining a safe workplace for all employees and contractors. The oil and gas industry has a number of inherent risks and our workers are often outdoors, in all seasons and all types of weather. In addition, our field personnel spend significant time driving on a daily basis, putting them at risk for driving accidents.
The final emissions guidelines under Subpart OOOOc provides until 2029 for existing sources to comply. As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain. We may incur costs as necessary to remain in compliance with these regulations.
As a result of these regulatory changes, the scope of any final air emissions regulations or the costs for complying with such regulations are uncertain. We may incur costs as necessary to remain in compliance with these regulations. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects.
We recognize that attracting, retaining and developing our employees is critical for our future success. Our Vice President General Counsel together with our Chief Executive Officer are responsible for developing and executing our 18 Table of Contents human capital strategy, with oversight by the Board of Directors and the board committees.
Our Senior Vice President General Counsel together with our Chief Executive Officer are responsible for developing and executing our human capital strategy, with oversight by the Board of Directors and the board committees. Some of our key human capital areas of focus include the following.
Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are GHG emissions.
Under these regulations, facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards for their GHG emissions established by the states or, in some cases, by the EPA, for those emissions.
Health and Safety Training and Education: We offer a wide range of training opportunities for employees and contractors to help them develop their skills and understanding of our health and safety policy and programs.
A strong safety culture is essential to our success, and we emphasize the important role that all personnel play in creating and maintaining a safe work environment. 18 Table of Contents Health and Safety Training and Education: We offer a wide range of training opportunities for employees and contractors to help them develop their skills and understanding of our health and safety policy and programs.
There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency. As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data in permit applications.
In Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water. There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability. Threatened and Endangered Species Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources.
Although it appears unlikely in the near term, more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of conducting business and consequently affecting our profitability.
Competitive Business Conditions We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas, and securing competent personnel. Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel.
Some of our competitors possess and employ financial resources substantially greater than ours and some of our competitors employ more technical personnel.
Additionally, the Trump administration may pursue a new rulemaking to further revise or clarify the extent of federal jurisdiction under the CWA, though the substance and timing of such action cannot be predicted. As such, uncertainty remains with respect to future implementation of the rule and the outcome of the pending litigation.
The Corps is currently pursuing a new post- Sackett rulemaking, the ultimate consequence of which cannot be predicted at this time. As such, uncertainty remains with respect to future implementation of the rule and the outcome of the pending litigation.
In August 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law. The IRA allocated $1.55 billion to the Methane Emissions and Waste Reduction Incentive Program. The IRA also required the EPA to implement a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds.
In August 2022, the Inflation Reduction Act of 2022 (“IRA”) was signed into law, which amended the CAA to establish the first ever federal fee on excess methane emissions from sources required to report their GHG emissions to the EPA, including certain oil and gas operations.
Removed
Lime Rock Purchase and Sale Agreement On February 25, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. ("LRRA") and Lime Rock Resources IV-C, L.P. ("LRRC" and with LRRA, "Lime Rock"), as seller, entered into a purchase and sale agreement (the "Purchase Agreement").
Added
Total proved developed reserves were 103.8 MMBoe at year-end 2025, which increased 11.2 MMBoe, or 12% from year-end 2024. • Maintained our revolving credit facility borrowing base of $585 million.
Removed
The Purchase Agreement provides that the Company will acquire (the "Lime Rock Acquisition") interests in oil and gas leases and related property of Lime Rock located in the Central Basin Platform of Texas for a purchase price (the "Purchase Price") of approximately $90 million in cash with $80 million due at closing and $10 million due on the nine months anniversary of closing, and 7,388,799 shares of our common stock.
Added
However, in March 2025, the EPA announced its intention to reconsider the March 2024 rule, including Subparts OOOOb and OOOOc, with a final rule expected in or around July 2026.
Removed
The Purchase Price is subject to customary purchase price adjustments with an effective date of October 1, 2024.
Added
A subsequent rule, finalized on November 26, 2025, gives states, along with federal tribes that wish to regulate existing sources, until January 2027 to develop and submit their plans for reducing methane emissions from existing sources.
Removed
On February 26, 2025, in connection with the Purchase Agreement, the Company deposited $5.0 million in cash into a third party escrow account as a deposit pursuant to the Purchase Agreement, which will be credited against the Purchase Price upon the closing of the Lime Rock Acquisition.
Added
In November 2024, the EPA issued a final rule implementing the methane emissions charge, although in February 2025, Congress repealed the rule under the Congressional Review Act. Additionally, under the One Big Beautiful Bill Act, enacted in July 2025 (“OBBBA”), Congress delayed the implementation of the methane emissions fee until 2034.
Removed
We believe that the 10 Table of Contents loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
Added
Additionally, in March 2025, the EPA announced formal reconsideration of the 2009 “Endangerment Finding”, a declaration that various greenhouse gases endanger public health and welfare and the basis for the majority of the EPA’s GHG-related regulations. In February 2026, the current administration finalized a rule repealing the Endangerment Finding.
Removed
The WEC for 2024 was $900 per metric ton of methane and increases to $1,200 in 2025 and $1,500 in 2026. In November 2024, the EPA finalized a rule implementing the WEC that took effect in January 2025.
Added
It is uncertain at this time what impact the repeal of the Endangerment Finding will have on such regulations.
Removed
The charge is designed to act as an incentive for operators to reduce emissions by minimizing leaks and replacing equipment rather than paying for excessive emissions. In February 2025, however, the U.S.
Added
Oil Pollution Prevention The OPA amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening WOTUS or adjoining shorelines. In 1973, the EPA adopted oil pollution prevention regulations under the CWA.
Removed
House and Senate approved a joint resolution of disapproval under the Congressional Review Act to repeal the methane emissions charge, which President Trump is expected to sign into law.
Added
The new rules went into effect on July 1, 2025. The new rules cover waste from oil and natural gas operations, such as rock and other material pulled up from the ground during drilling, as well as waste from other operations. The rules impose requirements related to waste management practices and production methods, such as recycling produced water.
Removed
While the State of Texas has not formally conducted recent rulemaking related to air emissions, scrutiny of oil and natural gas operations and the rules affecting them have increased in recent years.
Added
Although the EPA has proposed to delay GHG reporting for the oil and natural gas sector until 2034, and to otherwise repeal GHG reporting requirements for other sectors, we cannot predict whether these efforts will ultimately be successful or that GHG reporting will not be required again in the future.
Removed
For example, the EPA and environmental non-governmental organizations have conducted flyovers with optical gas imaging cameras to survey emissions from oil and natural gas production facilities and transmission infrastructure. In August 2022, for example, the EPA announced that it would be conducting helicopter flyovers of the Permian Basin region in Texas.
Added
The BLM has also, from time to time, considered or adopted rules regulating GHG emissions from oil and natural gas operations on federal lands. Nevertheless, there continues to be uncertainty surrounding the federal regulation of methane and other GHG emissions. Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations.
Removed
The flyovers used infrared cameras to survey oil and gas operations to identify large emitters of methane and volatile organic compounds ("VOCs"). Based on data obtained during flyovers, EPA intends to initiate enforcement follow up actions with facilities operators. In addition, the RRC has increased oversight related to flaring, with reporting reviews and site inspections.
Added
The current administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and promulgated a final rule, in February 2026, repealing the EPA’s 2009 “Endangerment Finding” that forms the basis for most of the EPA’s GHG-related rules.
Removed
While none of these activities increases our compliance obligations, they signal the potential for increased enforcement and possible rulemaking in the future. Oil Pollution Prevention The OPA amended the CWA to impose liability for releases of crude oil from vessels or facilities into navigable waters.
Added
However, whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulations, cannot be predicted at this time.
Removed
If a release of crude oil into navigable waters occurs during shipment or from an oil terminal, we could be subject to liability under the OPA. In 1973, the EPA adopted oil pollution prevention regulations under the CWA.
Added
While Congress has, from time to time, considered legislation to reduce emissions of GHGs, including proposals adopting cap-and-trade programs, carbon taxes, climate-related mitigation funds, and regulations that directly limit GHG emissions from select sources, no significant legislation has been adopted at the federal level.
Removed
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 have resulted in increased costs to operators, including us.
Added
While Congress previously enacted the Inflation Reduction Act of 2022 (the “IRA”) to advance climate-related objectives and provide financial support for alternative or lower GHG-emitting energy production, many of these incentives were repealed or otherwise modified following the change in Presidential administrations and the enactment of OBBBA.
Removed
In Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations of wells, and the disposal of waste oil and salt water. In October 2023, the RRC announced draft amendments to its water protection rules to, among other things, encourage waste recycling.
Added
However, any similar or future climate-related legislation and accompanying policy initiatives could increase operating costs within the oil and gas industry or accelerate a transition away from fossil fuels, which could in turn reduce demand for our products and adversely affect our business and results of operations.
Removed
In addition, in November 2016, the 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 CAA’s New Source Performance Standards in 40 C.F.R. Part 60, Subpart OOOOa (“GHG NSPS”) requirements.
Added
State, regional and local governments may also elect to continue to participate in international climate change initiatives, despite the current administration finalizing the United States’ withdrawal from such initiatives in 2026.
Removed
In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule, which became effective on November 27, 2018. Both the 2016 and the 2018 rule were challenged in federal court resulting in the rescission of both rules. Appeals to those decisions are ongoing, but with little activity in the last several years.
Added
The participation in, or support for, climate-related policies and initiatives by politicians, regulators, financial institutions, consumers, and other stakeholders could increase opposition against, reduce funding for or lead to new limitations on, fossil fuel exploration and production activities.
Removed
At the international level, there is an agreement, the United Nations-sponsored "Paris Agreement," for nations to limit their GHG emissions through non-binding, individually determined reduction goals every five years after 2020. The United States rejoined the Paris Agreement in February 2021.
Added
Threatened and Endangered Species Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds, wetlands, and natural resources. These statutes include the Endangered Species Act (“ESA”), the Migratory Bird Treaty Act (“MBTA”) and the CWA.

… 10 more changes not shown on this page.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

54 edited+10 added−19 removed113 unchanged
Biggest changeConsequently, our competitors may be able to address these competitive factors more effectively than we can. If we are not successful in our competition for oil and 24 Table of Contents natural gas properties or in our marketing of production, then our financial condition and operation results would be adversely affected.
Biggest changeIf we are not successful in our competition for oil and natural gas properties or in our marketing of production, then our financial condition and operation results would be adversely affected. If our access to markets is restricted, it could negatively impact our production, our income, and our ability to retain our leases.
Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage or use of surface water or ground water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations, and cash flows.
Any new environmental initiatives or regulations that restrict injection of fluids, including, but not limited to, produced water, drilling fluids and other wastes associated with the exploration, development or production of oil and gas, or that limit the withdrawal, storage, or use of surface water, ground water, or produced water necessary for hydraulic fracturing of our wells, could increase our operating costs and cause delays, interruptions, or cessation of our operations, the extent of which cannot be predicted, and all of which would have an adverse effect on our business, financial condition, results of operations, and cash flows.
If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and NGLs, which could have an adverse effect on our business, financial condition, and results of operations. Waste water from our operations typically are disposed of via underground injection.
If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil, natural gas and NGLs, which could have an adverse effect on our business, financial condition, and results of operations. Waste water from our operations typically is disposed of via underground injection.
In addition, the terms of our Second Credit Agreement have restrictions on dividend payments to our equity holders, including our common stockholders. Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect common stockholders.
In addition, the terms of our Credit Agreement have restrictions on dividend payments to our equity holders, including our common stockholders. Our Board of Directors can, without stockholder approval, cause preferred stock to be issued on terms that could adversely affect common stockholders.
Readers should carefully consider the risk factors included below as well as those matters referenced in this Report under “Forward-Looking Statements” and other information included and incorporated by reference into this Report.
Readers should carefully consider the risk factors included below as well as those matters referenced in this Annual Report under “Forward-Looking Statements” and other information included and incorporated by reference into this Annual Report.
Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.” (below) for a discussion of the uncertainty involved in these processes. Our cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular well or project uneconomical.
Please read “—Reserve estimates depend on many assumptions that may turn out to be inaccurate.” (below) for a discussion of the uncertainties involved in these processes. Our cost of drilling, completing, and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular well or project uneconomical.
Risks Relating to Technology and Cybersecurity We rely on computer and telecommunications systems, and failures in our systems or cyber security attacks or breaches could result in information theft, data corruption, disruption in operations, and/or financial loss. The oil and natural gas industry is highly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development, and production activities.
Risks Relating to Technology and Cybersecurity We rely on computer and telecommunications systems, and failures in our systems or cybersecurity attacks or breaches could result in information theft, data corruption, disruption in operations, and/or financial loss. The oil and natural gas industry is highly dependent upon digital technologies to conduct day-to-day operations including certain exploration, development, and production activities.
Our exploration and development activities and equipment can be adversely affected by extreme weather conditions, such as abnormally low temperatures, which can cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. For example, we had production stoppages in 2022, 2023, and 2024 that adversely affected our revenues.
Our exploration and development activities and equipment can be adversely affected by extreme weather conditions, such as abnormally low temperatures, which can cause a loss of production from temporary cessation of activity from regional power outages or lost or damaged facilities and equipment. For example, we had production stoppages in 2023, 2024, and 2025 that adversely affected our revenues.
The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control: • our operating and financial performance and prospects; • variations in our quarterly operating results and changes in our liquidity position; • investor perceptions of us and the industry and markets in which we operate; • future sales, or the availability for sale, of equity or equity-related securities; • changes in securities analysts’ estimates of our financial performance; • changes in market valuations of similar companies; • changes in the price of oil and natural gas; and • general financial, domestic, economic, and other market conditions.
The market price of our common stock may also fluctuate significantly in response to the following factors, some of which are beyond our control: • our operating and financial performance and prospects; • variations in our quarterly operating results and changes in our liquidity position; • investor perceptions of us and the industry and markets in which we operate; • future sales, or the availability for sale, of equity or equity-related securities; • changes in securities analysts’ estimates of our financial performance; • changes in market valuations of similar companies; 30 Table of Contents • changes in the price of oil and natural gas; and • general financial, domestic, economic, and other market conditions.
We continue to be impacted by inflationary pressures on our operating costs and capital expenditures. Beginning in the second half of 2021 and continuing throughout 2024, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars), labor, and drilling and completion services.
We continue to be impacted by inflationary pressures on our operating costs and capital expenditures. Beginning in the second half of 2021 and continuing throughout 2025, we, similar to other companies in our industry, experienced inflationary pressures on our operating costs and capital expenditures - namely the costs of fuel, steel (i.e., wellbore tubulars), labor, and drilling and completion services.
Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2025, have impacted our cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures.
Such inflationary pressures on our operating and capital costs, which we currently expect to continue in 2026, have impacted our cash flows and results of operations. We have undertaken, and plan to continue with, certain initiatives and actions (such as agreements with service providers to secure the costs and availability of services) to mitigate such inflationary pressures.
As we continue to expand, we will need to promote or hire additional staff, and, as a result of increased compensation and benefit packages in our industry, as well as inflationary pressures, it may be difficult to attract or retain such individuals without incurring significant additional costs.
As we continue to expand, we will need to promote or hire additional staff, and, as a result of increased compensation and benefit packages in our industry, as well as inflationary pressures, it may be difficult to attract or retain these individuals without incurring significant additional costs.
Changes in environmental laws and regulations and the interpretation thereof occur from time to time, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position, and financial condition as well as the industry in 26 Table of Contents general.
Changes in environmental laws and regulations and the interpretation thereof occur from time to time, and any changes that result in more stringent or costly waste handling, storage, transport, disposal, or cleanup requirements could require us to make significant expenditures to maintain compliance and may otherwise have a material adverse effect on our results of operations, competitive position, and financial condition as well as the industry in general.
Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price 23 Table of Contents during the preceding 12-month period determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts.
Discounted future net revenues are estimated using oil and natural gas spot prices based on the average price during the preceding 12-month period determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, except for changes which are fixed and determinable by existing contracts.
If we are unable to develop, find, or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of producing profitably. Competition is intense in the oil and natural gas industry.
If we are unable to develop, find, or acquire additional reserves to replace our current and future production, our cash flow and income will decline as production declines, until our existing properties would be incapable of producing profitably. 24 Table of Contents Competition is intense in the oil and natural gas industry.
Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which may be inconclusive or subject to varying interpretations.
Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the 22 Table of Contents results of which may be inconclusive or subject to varying interpretations.
The impacts of the United States’ withdrawal and other existing or future climate-related orders, pledges, agreements or any legislation or regulation promulgated in connection with the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time.
The impacts of 27 Table of Contents the United States’ withdrawal and other existing or future climate-related orders, pledges, agreements or any legislation or regulation promulgated in connection with the Paris Agreement, the Global Methane Pledge, or other international conventions cannot be predicted at this time.
However, there can be no assurance that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations.
However, there can be no assurance 29 Table of Contents that such efforts will offset, largely or at all, the impacts of any future inflationary pressures on our operating costs and capital expenditures and, in turn, our cash flows and results of operations.
For example, for the year ended December 31, 2024, we experienced a negative price of $1.44 per Mcf of natural gas with negative net sales of approximately $9.3 million, adversely affecting our cash flows and net income. Currently, some of our production is sold to marketers and other purchasers that have access to pipeline facilities.
For example, for the year ended December 31, 2025, we experienced a negative price of $1.33 per Mcf of natural gas with negative net sales of approximately $9.3 million, adversely affecting our cash flows and net income. Currently, some of our production is sold to marketers and other purchasers that have access to pipeline facilities.
Risks Relating to the Oil and Natural Gas Industry 21 Table of Contents A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
Risks Relating to the Oil and Natural Gas Industry A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.
In addition to the ability of the Board of Directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our 31 Table of Contents common stock.
In addition to the ability of the Board of Directors to issue preferred stock, the existence of some provisions under Nevada law could delay or prevent a change in control of the Company, which could adversely affect the price of our common stock.
Risks Relating to Our Business, Operations, and Strategy 19 Table of Contents Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application compared to vertical drilling.
Risks Relating to Our Business, Operations, and Strategy Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve additional risks and uncertainties in their application compared to vertical drilling.
Any such liabilities, penalties, suspensions, terminations, or regulatory changes could materially adversely affect our financial condition and results of operations. Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Any such liabilities, penalties, suspensions, terminations, or regulatory changes could materially adversely affect our financial condition and results of operations. 26 Table of Contents Our operations may incur substantial liabilities to comply with environmental laws and regulations.
Recent reluctance to invest in the exploration and production sector based on market volatility, historically perceived underperformance, and ESG trends, among other 29 Table of Contents things, has raised concerns regarding capital availability for the sector.
Recent reluctance to invest in the exploration and production sector based on market volatility, historically perceived underperformance, and ESG trends, among other things, has raised concerns regarding capital availability for the sector.
In addition, weaknesses in the cyber security of our vendors, suppliers, and other business partners could facilitate an attack on our technologies, systems, and networks.
In addition, weaknesses in the cybersecurity of our vendors, suppliers, and other business partners could facilitate an attack on our technologies, systems, and networks.
We must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds. Therefore, estimates of oil and natural gas reserves are inherently imprecise.
We must also analyze available geological, geophysical, production, and engineering data. The extent, quality, and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.
It is unclear 28 Table of Contents whether these or similar changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction.
It is unclear whether any such changes will be enacted and, if enacted, how soon any such changes could take effect. Additionally, states in which we operate or own assets may impose new or increased taxes or fees on oil and natural gas extraction.
Because a substantial percentage of our proved properties are proved undeveloped (approximately 31%), we will require significant additional capital to develop such properties before they may become productive.
Because a substantial percentage of our proved properties are proved undeveloped (approximately 32%), we will require significant additional capital to develop these properties before they may become productive.
The passage of any legislation as a result of these proposals and other changes in federal income tax laws or the imposition of new or increased taxes or fees on oil and natural gas extraction could adversely affect our operating results and cash flows.
The passage of any such legislation or other changes in federal income tax laws or the imposition of new or increased taxes or fees on oil and natural gas extraction could adversely affect our operating results and cash flows.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves.
Therefore, estimates of oil and natural gas reserves are inherently imprecise. 23 Table of Contents Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas reserves will likely vary from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reported reserves.
Based on our current interpretation of the IRA and the CAMT and a number of operational, economic, accounting and regulatory assumptions, we do not anticipate the CAMT materially increasing our U.S. federal income tax liability in the near term. The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT.
Based on our current interpretation of the IRA and the CAMT and a number of operational, 28 Table of Contents economic, accounting and regulatory assumptions, we do not anticipate the CAMT materially increasing our U.S. federal income tax liability in the near term.
To reduce our exposure to commodity price uncertainty and increase cash flow predictability, we have entered into crude oil and natural gas price hedging arrangements with respect to a significant portion of our expected production in order to economically hedge a portion of our forecasted oil and natural gas production.
To reduce our exposure to commodity price uncertainty and increase cash flow predictability, we have entered into crude oil and natural gas price hedging arrangements with respect to a significant portion of our expected production. Additionally, our credit facility requires us to hedge a significant portion of our production.
Natural disasters, adverse weather conditions (particularly abnormally cold weather in the winter, and hurricanes and thunderstorms in the summer), floods, pandemics, acts of terrorism and other catastrophic or geo-political events may cause damage or disruption to our operations and the global economy, or could result in market disruptions, any of which could have an adverse effect on our business, operating results, and financial condition.
Natural disasters, adverse weather conditions (particularly abnormally cold weather in the winter, and hurricanes and thunderstorms in the summer), floods, pandemics, acts of terrorism, and other catastrophic or geo-political events may cause damage or disruption to our operations and the global economy, or could result in market disruptions, any of which could have an adverse effect on our business, operating results, and financial condition. 21 Table of Contents The loss of key members of management or failure to attract and retain other highly qualified personnel could affect the Company’s business results.
Additionally, our credit facility requires us to hedge a significant portion of our production. These derivative contracts typically limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. Hedging transactions may expose us to risk of financial loss.
These derivative contracts typically limit the benefit we would otherwise receive from increases in the prices for oil and natural gas. Hedging transactions may expose us to risk of financial loss.
Further, the market's perception of future sales of common stock may adversely affect the price of our common stock. The market price of our common stock may be volatile, which could cause the value of your investment to decline. The stock markets have experienced volatility that has often been unrelated to the operating performance of particular companies.
Risks Relating to Our Common Stock The market price of our common stock may be volatile, which could cause the value of your investment to decline. The stock markets have experienced volatility that has often been unrelated to the operating performance of particular companies. These broad market fluctuations may adversely affect the trading price of our common stock.
Failure to ensure that we have the depth and breadth of management and personnel with the necessary skill sets and experience could impede our ability to achieve growth objectives and execute our operational strategy.
Our success depends on our ability to attract, retain and motivate a highly-skilled management team and workforce. Failure to ensure that we have the depth and breadth of management and personnel with the necessary skill sets and experience could impede our ability to achieve growth objectives and execute our operational strategy.
Many of our competitors have greater and more diverse resources than we do. Additionally, competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop, and operate properties. Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter.
Many of our competitors have greater and more diverse resources than we do. Additionally, competition for acquisitions may significantly increase the cost of available properties. We compete for the personnel and equipment required to explore, develop, and operate oil and gas properties.
Further, many factors may curtail, delay, or cancel drilling, including delays imposed by or resulting from compliance with regulatory requirements; pressure or irregularities in geological formations; shortages of or delays in obtaining equipment and qualified personnel; equipment failures or accidents; adverse weather conditions; reductions in oil and natural gas prices; title problems; and limitations in the market for oil and natural gas. 22 Table of Contents Decreases in oil and natural gas prices may require us to incur write-downs of the financial carrying values of our oil and natural gas properties which could negatively impact the price of our common stock.
Further, many factors may curtail, delay, or cancel drilling, including delays imposed by or resulting from compliance with regulatory requirements; pressure or irregularities in geological formations; shortages of or delays in obtaining equipment and qualified personnel; equipment failures or accidents; adverse weather conditions; reductions in oil and natural gas prices; title problems; and limitations in the market for oil and natural gas.
We have a Credit Facility in place with $600 million in commitments from borrowings and letters of credit under our Second Amended and Restated Credit Agreement dated August 31, 2022 with Truist Bank as Administrative Agent (the "Second Credit Agreement"). As of December 31, 2024, $385 million was outstanding on our Credit Facility.
We have a Credit Facility in place with $585 million in commitments from borrowings and letters of credit under our Third Amended and Restated Credit Agreement dated June 18, 2025 with Bank of America, N.A. as Administrative Agent (the "Credit Agreement"). As of December 31, 2025, $420 million was outstanding on our Credit Facility.
Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions.
Institutional lenders may elect in the future not to provide funding for oil and natural gas companies. Many of the largest U.S. banks have made net zero commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps quantify and reduce those emissions.
If our access to markets is restricted, it could negatively impact our production, our income, and our ability to retain our leases. Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production.
In the future, the U.S. Department of Treasury and the Internal Revenue Service are expected to release regulations and interpretive guidance relating to the CAMT, and any significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and adversely affect our operating results and cash flows.
Any significant variance from our current interpretation could result in a change in the expected application of the CAMT to us and adversely affect our operating results and cash flows.
Extreme weather conditions, which could become more frequent or severe due to multiple factors, could adversely affect our ability to conduct drilling, completion, and production activities in the areas where we operate.
As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions to ongoing production. 25 Table of Contents Extreme weather conditions, which could become more frequent or severe due to multiple factors, could adversely affect our ability to conduct drilling, completion, and production activities in the areas where we operate.
The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an impairment expense. During the years ended December 31, 2024, 2023, and 2022 we did not incur any write-downs.
The net book value is compared to the ceiling on a quarterly basis. The excess, if any, of the net book value above the ceiling is required to be written off as an impairment expense. During the year ended December 31, 2025, we recorded a non-cash write down of $108.8 million.
We are unable to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable.
We are unable to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. This risk may be enhanced in our situation, due to the fact that a significant percentage of our proved reserves is currently proved undeveloped reserves.
The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following: • unforeseen title issues; • the amount of recoverable reserves; • future oil and natural gas prices; • estimates of operating costs; • estimates of future development costs; • estimates of the costs and timing of plugging and abandonment of wells; and • potential environmental and other liabilities.
The successful acquisition of producing properties requires assessments of many factors, which are inherently inexact and may be inaccurate, including the following: • unforeseen title issues; • the amount of recoverable reserves; • future oil and natural gas prices; • estimates of operating costs; • estimates of future development costs; • estimates of the costs and timing of plugging and abandonment of wells; and • potential environmental and other liabilities. 20 Table of Contents Our assessments will not reveal all existing or potential problems, nor will they permit us to become familiar enough with the potential properties we may acquire to assess fully their capabilities and deficiencies.
These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations. 25 Table of Contents Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
These constraints and the resulting shortages or high costs could delay or temporarily halt our operations and materially increase our operation and capital costs, which could have a material adverse effect on our business, financial condition, and results of operations.
Further, state and local governments, financial institutions, and industry groups may elect to continue participating in international climate-related initiatives.
Further, state and local governments, financial institutions, and industry groups may elect to continue participating in international climate-related initiatives. Increasingly, oil and natural gas companies are exposed to litigation risks associated with the threat of climate change.
Accounting rules require that we review periodically the financial carrying value of our oil and natural gas properties for possible impairment.
Decreases in oil and natural gas prices may require us to incur write-downs of the financial carrying values of our oil and natural gas properties which could negatively impact the price of our common stock. Accounting rules require that we review periodically the financial carrying value of our oil and natural gas properties for possible impairment.
Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods. Future price decreases could result in reductions in the financial carrying value of such assets and an equivalent charge on our financial statements.
During the years ended 2024 and 2023 we did not incur any write-downs. Under SEC full cost accounting rules, any write-off recorded may not be reversed even if higher oil and natural gas prices increase the ceiling applicable to future periods.
In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
In addition, problems affecting one pad could adversely affect production from all wells on the pad.
Moreover, federal regulators, state and local governments, and private parties have taken (or announced that they plan to take) actions that have or may have a significant influence on our operations. International climate commitments made by political, industrial, and financial stakeholders may also impact commercial, regulatory, and consumer trends related to climate change.
International climate commitments made by political, industrial, and financial and other stakeholders may also impact commercial, regulatory, and consumer trends related to climate change.
However, in January 2025, President Trump initiated the United States’ withdrawal from the Paris Agreement and ordered the revocation of any related financial commitments.
However, in January 2025, the current administration ordered the revocation of any United States financial commitments on emission goals associated with international climate agreements. Then, in January 2026, the United States finalized its withdrawal from the Paris Agreement.
Our assessments will not reveal all existing or potential problems, nor will they permit us to become familiar enough with the potential properties we may acquire to assess fully their capabilities and deficiencies. We plan to undertake further development of our properties generally through the use of cash flow from existing production.
We plan to undertake further development of our properties generally through the use of cash flow from existing production.
Removed
This risk may be enhanced in our situation, due to the 20 Table of Contents fact that a significant percentage of our proved reserves is currently proved undeveloped reserves.
Added
Future price decreases could result in reductions in the financial carrying value of such assets and an equivalent charge on our financial statements.
Removed
The recent coronavirus outbreak impacted various businesses throughout the world, including an impact on the global demand for oil and natural gas, travel restrictions and the extended shutdown of certain businesses in impacted geographic regions. If other pandemics occur, they could have a material adverse impact on our business operations, operating results and financial condition.
Added
Our competitors also may have established long-term strategic positions and relationships in areas in which we may seek to enter. Consequently, our competitors may be able to address these competitive factors more effectively than we can.
Removed
The loss of key members of management or failure to attract and retain other highly qualified personnel could affect the Company’s business results. Our success depends on our ability to attract, retain and motivate a highly-skilled management team and workforce.
Added
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in some of the areas where we operate.
Removed
The IRA also imposes the first-ever fee on GHG emissions through a WEC, which the EPA has finalized regulations to implement. In May 2024, the EPA published a final rule expanding GHG emissions reporting obligations for certain oil and natural gas sector sources.
Added
The OBBBA rescinds or eliminates funding for multiple programs under the IRA aimed at reducing or monitoring GHG emissions and other air pollutants, such as the Greenhouse Gas Reduction Fund and methane monitoring initiatives.
Removed
While the first Trump administration took a number of actions to revise federal regulation of methane from the oil and natural gas sector, these actions were subsequently reversed by both the Biden administration and Congress.
Added
While the OBBBA will potentially affect federal efforts to address climate change and emissions reductions, various federal agencies have, from time to time, adopted climate change considerations into their rulemaking and decision-making processes and have promulgated regulations that seek to restrict, monitor, or otherwise limit GHG emissions.
Removed
Moreover, in December 2023, the EPA published a final rule that established more stringent performance standards for new sources and first-time standards for existing sources under applicable agency regulations at 40 C.F.R. Part 60 for methane and VOC emissions for the crude oil and natural gas sources.
Added
Federal policy towards GHG emissions, and regulation thereunder, has varied significantly between the past several Presidential administrations. The current administration has expressed a policy preference of limiting or rescinding regulations concerning GHG emissions and, in February 2026, promulgated a final rule repealing the EPA’s 2009 “Endangerment Finding” and its motor vehicle GHG emission performance standards.
Removed
The requirements imposed by this rule include enhanced leak detection and repair obligations, zero-emission requirements for certain processes and practices, “green well” completion standards, limitations on routine flaring, and a “Super Emitter Response Program” which triggers additional requirements following certain large emissions events.
Added
This rescission of the “Endangerment Finding” eliminates the basis for EPA’s authority under the CAA for most of its regulations concerning GHGs.
Removed
Compliance with these rules and legislation will likely require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, increased frequency of maintenance and repair activities to address emissions leakage and additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance.
Added
However, whether or how such policies and the EPA’s rescission of its “Endangerment Finding” will be implemented and if they will survive any potential legal challenges, or whether future administrations or Congress may pursue new GHG emissions regulation, cannot be predicted at this time.
Removed
While legal challenges to many of the above discussed regulations are ongoing and, either the current Trump administration or Congress may also pursue rulemakings or legislation, respectively, that could repeal, revise, or otherwise limit the enforcement of these regulations and certain of the IRA’s provisions, like the WEC, we cannot predict whether and when such action will be taken and the outcome and timeline for such actions may continue to be uncertain and subject to further legal challenges.
Added
At the international level, the United Nations-sponsored Paris Agreement encourages nations to limit their GHG emissions through nationally-determined, though non-binding, reduction goals.
Removed
Internationally, the United Nations-sponsored “Paris Agreement” encourages member states to individually determine and submit non-binding emissions reduction targets. The United States’ most recent goal was to reduce its economy-net GHG emissions by 61 to 66 percent from 2005 levels by 2035.
Added
The foregoing analysis is based upon our current interpretation of the provisions contained in the IRA and the CAMT. The U.S. Department of the Treasury and the Internal Revenue Service have released proposed regulations and other interpretive guidance relating to the CAMT.
Removed
In addition, on March 6, 2024, the SEC adopted a rule requiring registrants to include certain climate-related disclosures, including Scope 1 and 2 GHG emissions, climate-related targets and goals, and certain climate-related 27 Table of Contents financial statement metrics, in registration statements and annual reports, though the implementation of this rules is currently paused pending the outcome of legal challenges against the rule.
Removed
Currently, the ultimate impact of these laws on our business is uncertain.
Removed
Separately, enhanced climate related disclosure requirements could lead to reputational or other harm with customers, regulators, investors, or other stakeholders and could also increase our litigation risks relating to statements alleged to have been made by us or others in our industry regarding climate change risks, or in connection with any future disclosures we may make regarding reported emissions, particularly given the inherent uncertainties and estimations with respect to calculating and reporting GHG emissions.
Removed
Additionally, the SEC has also from time to time applied additional scrutiny to existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures misleading or deficient. Increasingly, oil and natural gas companies are exposed to litigation risks associated with the threat of climate change.
Removed
Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices, and some of them may elect in the future not to provide funding for oil and natural gas companies.
Removed
Such legislative changes have included, but have not been limited to, (i) the elimination of the percentage depletion allowance for oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) an extension of the amortization period for certain geological and geophysical expenditures, (iv) the elimination of certain other tax deductions and relief previously available to oil and natural gas companies, and (v) an increase in the federal income tax rate applicable to corporations such as us.

… 3 more changes not shown on this page.

Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

8 edited+0 added−0 removed8 unchanged
Biggest changeThe Board and Audit Committee are supported in their oversight capacity by our Management Cybersecurity Committee (the “MC Committee”) and our internal auditors. The MC Committee consists of our CEO, CFO, EVP of Engineering and Corporate Strategy, Vice President - General Counsel, and our IT Manager.
Biggest changeThe Board and Audit Committee are supported in their oversight capacity by our Management Cybersecurity Committee (the “MC Committee”) and our internal auditors. The MC Committee consists of our CEO, Interim CFO, Chief Operations Officer, Senior Vice President General Counsel, and our Director of IT.
Our internal auditors perform audit engagements to assess our strategies, policies, procedures, and controls to reduce the risk of a cybersecurity incident. Our IT Manager is responsible for assessing and managing risks from cybersecurity threats, guiding our overall cybersecurity risk management program, and supervising both our internal cybersecurity personnel and our retained external cybersecurity consultants.
Our internal auditors perform audit engagements to assess our strategies, policies, procedures, and controls to reduce the risk of a cybersecurity incident. Our Director of IT is responsible for assessing and managing risks from cybersecurity threats, guiding our overall cybersecurity risk management program, and supervising both our internal cybersecurity personnel and our retained external cybersecurity consultants.
Engagement of Third Parties The MC Committee, internal auditors, our IT Manager and various other groups each occasionally engage third-party service providers to assist in their management of cybersecurity threats, including but not limited to cybersecurity vendors, assessors, consultants, auditors, and other third parties.
Engagement of Third Parties The MC Committee, internal auditors, our Director of IT and various other groups each occasionally engage third-party service providers to assist in their management of cybersecurity threats, including but not limited to cybersecurity vendors, assessors, consultants, auditors, and other third parties.
Our IT Manager oversees third party vendors to identify cyber risks associated with our use of third-party service providers who may have access to sensitive Company data and systems.
Our Director of IT oversees third party vendors to identify cyber risks associated with our use of third-party service providers who may have access to sensitive Company data and systems.
Our cybersecurity risk management program includes, but is not limited to, the following key elements: • risk assessments designed to help identify material cybersecurity risks to our critical systems and information; • a Manager of Information Technologies (“IT Manager”) responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents; • the use of external service providers, where appropriate, to assess, test, or otherwise assist with aspects of our security processes; • systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall, and anti-virus software; and • cybersecurity awareness training of our employees, including incident response personnel, and senior management.
Our cybersecurity risk management program includes, but is not limited to, the following key elements: • risk assessments designed to help identify material cybersecurity risks to our critical systems and information; 31 Table of Contents • a Director of Information Technologies and Cybersecurity (“IT Director”) responsible for managing our cybersecurity risk assessment processes, our security controls, and our response to cybersecurity incidents; • the use of external service providers, where appropriate, to assess, test, or otherwise assist with aspects of our security processes; • systems for protecting information technology systems and monitoring for suspicious events, such as threat protection, firewall, and anti-virus software; and • cybersecurity awareness training of our employees, including incident response personnel, and senior management.
There can be no assurance that our cybersecurity risk management program, including our controls, procedures and processes will be fully effective in protecting the confidentiality, integrity, and availability of our information systems.
There can be no assurance that our cybersecurity risk management program, including our controls, procedures and processes will be fully effective in protecting the confidentiality, integrity, and availability of our 32 Table of Contents information systems.
While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security that they will not be subject to cybersecurity attacks and any damages to us from such attacks.
While we devote resources to our security measures to protect our systems and information, these measures cannot provide absolute security that they will not be subject to cybersecurity attacks and any damages to us from such attacks. 33 Table of Contents
Our IT Manager is responsible for reporting material incidents to our MC Committee. 32 Table of Contents Our IT Manager has a Bachelor of Science in Computer Science from Texas A&M University and a Master of Business Administration from Rice University. He has over 16 years of information technology experience in the energy industry.
Our Director of IT is responsible for reporting material incidents to our MC Committee. Our Director of IT has a Bachelor of Science in Computer Science from Texas A&M University and a Master of Business Administration from Rice University. He has over 17 years of information technology experience in the energy industry.

Item 2. Properties

Properties — owned and leased real estate

65 edited+19 added−9 removed30 unchanged
Biggest changeThe following table sets forth our gross and net undeveloped acreage, as of December 31, 2024, under lease that will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates: Undeveloped Acreage 2025 2026 2027 Gross Net Gross Net Gross Net Central Basin Platform 640 115 240 108 1,223 996 Northwest Shelf 7,051 3,450 2,192 524 1,627 452 Total 7,691 3,565 2,432 632 2,850 1,448 42 Table of Contents Production History The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2024, 2023, and 2022: Years ended December 31, 2024 2023 2022 Oil (Bbls) Central Basin Platform 2,851,788 2,347,068 1,409,211 Delaware Basin (2) — 25,743 81,936 Northwest Shelf 2,009,840 2,207,131 1,968,693 Total 4,861,628 4,579,942 3,459,840 Natural Gas (Mcf) (1) Central Basin Platform 3,808,653 3,940,107 1,563,808 Delaware Basin (2) — 11,265 96,516 Northwest Shelf 2,615,021 2,387,786 2,428,318 Total 6,423,674 6,339,158 4,088,642 Natural Gas Liquids (Bbls) (1) Central Basin Platform 749,794 703,818 227,996 Delaware Basin (2) — 2,867 3,718 Northwest Shelf 509,020 270,167 139,615 Total 1,258,814 976,852 371,329 Total production (Boe) Central Basin Platform 4,236,357 3,707,571 1,897,842 Delaware Basin (2) — 30,488 101,740 Northwest Shelf 2,954,697 2,875,262 2,513,028 Total 7,191,054 6,613,321 4,512,610 Daily production (Boe/d) Central Basin Platform 11,575 10,158 5,200 Delaware Basin (2) — 84 279 Northwest Shelf 8,073 7,877 6,885 Total 19,648 18,119 12,364 (1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales.
Biggest changeThe following table sets forth our gross and net undeveloped acreage, as of December 31, 2025, under lease that will expire over the next three years unless (i) production is established on the lease or within a spacing unit of which the lease is participating, or (ii) the lease is renewed or extended prior to the relevant expiration dates: Undeveloped Acreage 2026 2027 2028 Gross Net Gross Net Gross Net Central Basin Platform 600 130 963 963 1,628 331 Northwest Shelf 2,030 516 530 527 972 679 Total 2,630 646 1,493 1,490 2,600 1,010 44 Table of Contents Production History The following table presents the historical information regarding our produced oil, natural gas and natural gas liquid volumes for the years ended December 31, 2025, 2024, and 2023: Years ended December 31, 2025 2024 2023 Oil (Bbls) Central Basin Platform 2,974,051 2,851,788 2,347,068 Delaware Basin (1) — — 25,743 Northwest Shelf 1,867,113 2,009,840 2,207,131 Total 4,841,164 4,861,628 4,579,942 Natural Gas (Mcf) (1) Central Basin Platform 3,825,915 3,808,653 3,940,107 Delaware Basin (1) — — 11,265 Northwest Shelf 3,155,043 2,615,021 2,387,786 Total 6,980,958 6,423,674 6,339,158 Natural Gas Liquids (Bbls) Central Basin Platform 747,527 749,794 703,818 Delaware Basin (1) — — 2,867 Northwest Shelf 640,291 509,020 270,167 Total 1,387,818 1,258,814 976,852 Total production (Boe) Central Basin Platform 4,359,231 4,236,357 3,707,571 Delaware Basin (1) — — 30,488 Northwest Shelf 3,033,245 2,954,697 2,875,262 Total 7,392,476 7,191,054 6,613,321 Daily production (Boe/d) Central Basin Platform 11,943 11,575 10,158 Delaware Basin (1) — — 84 Northwest Shelf 8,310 8,073 7,877 Total 20,253 19,648 18,119 (1) The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023. 45 Table of Contents Production Prices and Production Costs The following tables provides historical pricing and costs statistics for the years ended December 31, 2025, 2024, and 2023.
As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu of Henry Hub natural gas.
As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu Henry Hub natural gas.
As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas.
As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu of Henry Hub natural gas.
We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies.
We present the pre-tax PV-10 value, which is a non-GAAP financial measure, because it is a widely used industry standard which we believe is useful to those who may review this Annual Report when comparing our asset base and performance to other comparable oil and natural gas exploration and production companies.
In 2024, the Company did not purchase any additional reserves. • Sales of minerals in place. In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties. • Revision of previous estimates.
In 2024, the Company did not purchase any additional reserves. • Sales of minerals in place. In 2024, the Company sold 1.2 MMBoe from the divestiture of certain oil and gas properties, including vertical wells and associated facilities, within the Central Basin Platform in Andrews and Gaines Counties. • Revision of previous quantity estimates.
The horizontal wells predominately produce from the San Andres conventional reservoir and the vertical wells produce from a variety of conventional pay sands including Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs . Title to Properties We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests.
The horizontal wells predominately produce from the San Andres conventional reservoir and the vertical wells produce from a variety of conventional pay zones including the Holt, Glorieta, Clear Fork, Wichita Albany, Tubb, Wolfcamp and Devonian reservoirs . Title to Properties We generally conduct a preliminary title examination prior to the acquisition of properties or leasehold interests.
Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines. 37 Table of Contents The standardized measure of discounted future net cash flows relating to the proved oil, natural gas, and NGLs reserves are shown below.
Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines. 38 Table of Contents The standardized measure of discounted future net cash flows relating to the proved oil, natural gas, and NGLs reserves are shown below.
Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2024 and 2023, respectively, in accordance with SEC guidelines.
Our estimates of reserves and future cash flow as of December 31, 2025 and 2024 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2025 and 2024, respectively, in accordance with SEC guidelines.
In 2024, the negative revisions of prior reserves of 5.6 MMBoe consisted of a positive 0.2 MMBoe (4%) related to changes in price (including differentials and gathering related contract change that effects differentials) offset by a negative 5.8 MMBoe (104%) related to changes in performance and other economic factors.
In 2024, the negative revisions of prior reserves of 5.6 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials) offset by a negative 5.8 MMBoe related to changes in performance and other economic factors.
Productive Wells The following table presents our ownership as of December 31, 2024 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Approximately 99.8% of such wells are in the Permian Basin in Texas.
Productive Wells The following table presents our ownership as of December 31, 2025 in productive oil and natural gas wells (a net well is our percentage ownership of a gross well). Approximately 99.8% of such wells are in the Permian Basin in Texas.
To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using volumetric estimates or performance from analogous wells in the surrounding area.
To establish reasonable certainty with respect to our estimated proved reserves, the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area.
The methane charge became effective in 2024 at $900 per metric ton of methane, and is set to increase to $1,200 per metric ton of methane for 2025, and $1,500 per metric ton of methane by 2026 and thereafter.
The methane charge became effective in 2024 at $900 per metric ton of methane, and was set to increase to $1,200 per metric ton of methane for 2025, and $1,500 per metric ton of methane by 2026 and thereafter.
The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; • the accuracy of economic assumptions; and • the judgment of the personnel preparing the estimates.
The accuracy of the reserve estimates is dependent on many factors, including the following: • the quality and quantity of available data and the engineering and geological interpretation of that data; • estimates regarding the amount and timing of future costs, which could vary considerably from actual costs; 42 Table of Contents • the accuracy of economic assumptions; and • the judgment of the personnel preparing the estimates.
In 2022, we acquired properties consisting of approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we acquired properties in Ector County.
In 2022, we acquired properties consisting of 34 Table of Contents approximately 37,000 net acres, with an average working interest of 99% and an average net revenue interest of 88% for oil and 96% for natural gas in our initial leases in Crane, Winkler, and Ward counties. In 2023, we acquired properties in Ector County.
("CGA"), independent petroleum engineers. These reserves are 35 Table of Contents attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas, and natural gas liquid reserves is shown below.
("CGA"), independent petroleum engineers. These reserves are attributable solely to properties within the United States. A summary of the changes in quantities of proved (developed and undeveloped) oil, natural gas, and natural gas liquid reserves is shown below.
Proved Undeveloped Reserves Our reserve estimates as of December 31, 2024 include approximately 41.6 MMBoe as PUDs. As of December 31, 2023, our reserve estimates included approximately 41.6 MMBoe as PUDs. In accordance with our December 31, 2024 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification.
Proved Undeveloped Reserves Our reserve estimates as of December 31, 2025 include approximately 49.5 MMBoe as PUDs. As of December 31, 2024, our reserve estimates included approximately 41.6 MMBoe as PUDs. In accordance with our December 31, 2025 year-end independent engineering reserve report, we plan to drill our PUD drilling locations within five years of original classification.
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, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr.
Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 22, 2026, filed as an exhibit to this Annual Report, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. 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.
Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 38 years of practical experience in petroleum engineering, with over 36 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr.
We spent approximately $391.6 million on acquisitions and capital projects during 2024 and 2023. We expect to further develop these properties through additional drilling. The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2024.
We spent approximately $335.8 million on acquisitions and capital projects during 2025 and 2024. We expect to further develop these properties through additional drilling. The following table summarizes our total net proved reserves, pre-tax PV-10 value and Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2025.
The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in Mcf. The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls.
The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls. The average natural gas sales price amounts above are calculated by dividing revenue from natural gas sales by the volume of natural gas sold, in Mcf.
Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC). As of December 31, 2024, approximately 69% of the proved reserves were classified as PD and the remaining 31% were PUD.
Our reserve estimates have not been filed with any Federal authority or agency (other than the SEC). As of December 31, 2025, approximately 68% of the proved reserves were classified as PD and the remaining 32% were PUD.
As shown in the aforementioned table, our average production taxes, per Boe, 45 Table of Contents were $2.24 and $2.74 for the years ended December 31, 2024 and 2023, respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.
As shown in the aforementioned table, our average production taxes, per Boe, were $1.94, $2.24, and $2.74 for the years ended December 31, 2025, 2024, and 2023 respectively. These amounts are calculated by dividing our total production costs or total production taxes by our total volume sold, in Boe.
Below is a description of the changes in our PUD reserves from December 31, 2023 to December 31, 2024. Notable changes in proved undeveloped reserves for the year ended December 31, 2024 included the following: • Conversions to developed.
Below is a description of the changes in our PUD reserves from December 31, 2024 to December 31, 2025. 40 Table of Contents Notable changes in proved undeveloped reserves for the year ended December 31, 2025 included the following: • Conversions to developed.
Each quarter, the Corporate Reserves team along with the Executive Vice President of Engineering and Corporate Strategy presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives.
Each quarter, the Corporate Reserves team along with the Executive Vice President and Chief Operations Officer presents the status of the Company’s reserves to senior executives, and subsequently obtains approval of significant changes from key executives.
Our Executive Vice President of Engineering and Corporate Strategy, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 18 years of practical industry experience, including over 14 years of estimating and evaluating reserve information.
Our Executive Vice President and Chief Operations Officer, Mr. Alex Dyes, is the technical professional primarily responsible for overseeing the preparation of our reserves estimates. He has a Bachelor of Science degree in Petroleum Engineering from the University of Texas with over 19 years of practical industry experience, including over 15 years of estimating and evaluating reserve information.
Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer; Chief Financial Officer; Executive Vice President of Engineering and Corporate Strategy; Vice President of Operations; Executive Vice President, Exploration and Geosciences; and Vice President, General Counsel.
Additionally, our five-year PUD development plan is reviewed and approved annually by the Company’s Chief Executive Officer; Vice President and Interim Chief Financial Officer; Executive Vice President and Chief Operations Officer; Senior Vice President of Operations; Executive Vice President and Chief Exploration Officer; and Senior Vice President, General Counsel.
Oil (Bbl) Gas (Mcf) (2) Natural Gas Liquids (Bbl) (2) Boe (1) Balance, December 31, 2022 88,704,743 157,870,449 23,105,658 138,122,143 Purchase of minerals in place 6,543,640 3,372,965 1,089,382 8,195,183 Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768 Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700) Production (4,579,942) (6,339,158) (976,852) (6,613,320) Revisions of previous quantity estimates (6,728,088) (9,946,459) (621,014) (9,006,845) Balance, December 31, 2023 82,141,277 146,396,322 23,218,564 129,759,229 Purchase of minerals in place — — — — Extensions, discoveries and improved recovery 11,495,236 10,630,769 2,738,451 16,005,482 Sales of minerals in place (1,140,568) (56,020) (16,361) (1,166,266) Production (4,861,628) (6,423,674) (1,258,814) (7,191,054) Revisions of previous quantity estimates (6,730,246) (730,235) 3,621,245 (3,230,707) Balance, December 31, 2024 80,904,071 149,817,162 28,303,085 134,176,684 (1) Six Mcf is deemed the equivalent of one Boe.
Oil (Bbl) Gas (Mcf) Natural Gas Liquids (Bbl) Boe (1) Balance, December 31, 2022 88,704,743 157,870,449 23,105,658 138,122,143 Purchase of minerals in place 6,543,640 3,372,965 1,089,382 8,195,183 Extensions, discoveries and improved recovery 3,098,845 4,113,480 1,014,343 4,798,768 Sales of minerals in place (4,897,921) (2,674,955) (392,953) (5,736,700) Production (4,579,942) (6,339,158) (976,852) (6,613,320) Revisions of previous quantity estimates (2) (6,728,088) (9,946,459) (621,014) (9,006,845) Balance, December 31, 2023 82,141,277 146,396,322 23,218,564 129,759,229 Purchase of minerals in place — — — — Extensions, discoveries and improved recovery 11,495,236 10,630,769 2,738,451 16,005,482 Sales of minerals in place (1,140,568) (56,020) (16,361) (1,166,266) Production (4,861,628) (6,423,674) (1,258,814) (7,191,054) Revisions of previous quantity estimates (2) (6,730,246) (730,235) 3,621,245 (3,230,707) Balance, December 31, 2024 80,904,071 149,817,162 28,303,085 134,176,684 Purchase of minerals in place 9,915,483 10,067,543 2,373,336 13,966,743 Extensions, discoveries and improved recovery 7,281,553 10,624,783 2,133,786 11,186,136 Sales of minerals in place — — — — Production (4,841,164) (6,980,958) (1,387,818) (7,392,476) Revisions of previous quantity estimates (2) (2,939,895) 12,652,046 2,171,955 1,340,734 Balance, December 31, 2025 90,320,048 176,180,576 33,594,344 153,277,821 (1) Six Mcf is deemed the equivalent of one Boe.
Of this, 5.00 gross (4.94 net) horizontal San Andres wells were in the Northwest Shelf in Yoakum County (four 1.0-mile laterals and one 1.5-mile lateral) and 39.00 gross (39.00 net) wells were in the Central Basin Platform, of which seventeen were horizontal San Andres wells in Andrews County and Crane County, Texas (all 1.0-mile laterals) and 22.00 were vertical wells in Crane County, and Ector County, Texas.
Of this, 5.00 gross (4.00 net) horizontal San Andres wells were in the Northwest Shelf in Yoakum County (three 1.0-mile laterals, one 1.25-mile lateral, and one 1.5-mile lateral) and 13.00 gross (13.00 net) wells were in the Central Basin Platform, of which 7.00 were horizontal wells in Andrews County and Crane County, Texas (all 1.0-mile laterals,) and 6.00 were vertical wells in Crane County, and Ector County, Texas.
Summary of Oil and Natural Gas Reserves As of December 31, 2024, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows of 34 Table of Contents approximately $1,232.9 million, over 99.7% of which relates to our properties in the Permian Basin in Texas.
Summary of Oil and Natural Gas Reserves As of December 31, 2025, our estimated proved reserves had a pre-tax PV-10 value (present value discounted at 10%) of approximately $1,318.2 million and a Standardized Measure of Discounted Future Net Cash Flows of approximately $1,123.5 million, over 99.8% of which relates to our properties in the Permian Basin in Texas.
Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2024, 2023 and 2022 are shown below: 2024 2023 2022 Payments to acquire oil and natural gas properties $ 2,210,826 $ 82,900,900 $ 179,387,490 Payments to explore oil and natural gas properties — — — Payments to develop oil and natural gas properties 153,945,456 152,559,314 129,332,155 Total costs incurred $ 156,156,282 $ 235,460,214 $ 308,719,645 Other Properties and Commitments Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas.
Costs incurred for property acquisition, exploration and development activities for the years ended December 31, 2025, 2024 and 2023 are shown below: 2025 2024 2023 Payments to acquire oil and natural gas properties $ 84,392,361 $ 2,210,826 $ 82,900,900 Payments to explore oil and natural gas properties — — — Payments to develop oil and natural gas properties 95,207,027 153,945,456 152,559,314 Total costs incurred $ 179,599,388 $ 156,156,282 $ 235,460,214 Other Properties and Commitments Effective January 1, 2021, the Company moved its corporate headquarters to The Woodlands, Texas.
Within the Northwest Shelf, we have a total of 35 proved undeveloped locations (100% horizontal) and 3 PDNP opportunities based on the reserve report as of December 31, 2024. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs.
Within the Northwest Shelf, we have a total of 33 proved undeveloped locations (100% horizontal) and 2 PDNP opportunities based on the reserve report as of December 31, 2025. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Northwest Shelf leases contain additional potential drilling locations.
As of December 31, 2024, the Company had interests in approximately five gross vertical and 151 gross horizontal producing wells, of which we operate five vertical and 116 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the verticals produce from Wolfcamp reservoir.
As of December 31, 2025, the Company had interests in approximately seven gross vertical and 136 gross horizontal producing wells, of which we operate seven vertical and 120 horizontal wells. The horizontal wells predominately produce from the San Andres conventional reservoir and the vertical wells produce from the Wolfcamp reservoir.
The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
The average NGL sales price amounts above are calculated by dividing revenue from NGL sales by the volume of NGLs sold, in Bbls. The total average sales price amounts are calculated by dividing total revenues by total volume sold, in Boe. The average production costs above are calculated by dividing production costs by total production in Boe.
In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors. 36 Table of Contents Our proved oil, natural gas, and natural gas liquid reserves are shown below.
In 2024, the negative revisions of prior reserves of 3.2 MMBoe consisted of a positive 0.2 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials), offset by a negative 3.4 MMBoe related to changes in performance and other economic factors.
For the year ended December 31, 2024 2023 2022 Gross Net Gross Net Gross Net Exploratory Productive — — — — — — Dry — — — — — — Development Productive (1) 43.00 42.94 31.00 29.75 32.00 31.35 Dry — — — — — — Total Productive 43.00 42.94 31.00 29.75 32.00 31.35 Dry — — — — — — (1) One of the 44.00 drilled wells has been drilled but not yet completed as of December 31, 2024.
For the years ended December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Exploratory Productive — — — — — — Dry — — — — — — Development Productive (1) 18.00 17.00 43.00 42.94 31.00 29.75 Dry — — — — — — Total Productive 18.00 17.00 43.00 42.94 31.00 29.75 Dry — — — — — — (1) One of the 44.00 drilled wells was drilled but not yet completed as of December 31, 2024.
Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs.
(2) Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history, a rule that undeveloped reserves must be drilled within five years of originally being booked, and/or resulting from a change in economic factors, such as commodity prices, operating costs or development costs. 36 Table of Contents Notable changes in proved reserves for the year ended December 31, 2025 included the following: • Extensions.
As of December 31, 2024, our total proved reserves had a net pre-tax PV-10 value of approximately $1,462.8 million and a Standardized Measure of Discounted Future Net Cash Flows ("SMOG") of approximately $1,232.9 million.
As of December 31, 2025, our total proved reserves had a net pre-tax PV-10 value of approximately $1,318.2 million and a Standardized Measure of Discounted Future Net Cash Flows ("SMOG") of approximately $1,123.5 million.
Cost Information We conduct our oil and natural gas activities entirely in the United States. As can be calculated from the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, transportation and transportation ("GTP") and ad valorem, per Boe, were $12.08 and $11.70 for the years ended December 31, 2024 and 2023, respectively.
As can be calculated from the table under “Production Prices and Production Costs”, our average production costs including lease operating expenses, gathering, transportation and processing ("GTP") and ad valorem, per Boe, were $11.88, $12.08, and $11.70 for the years ended December 31, 2025, 2024, and 2023 respectively.
In 2024, we sold 0.1 MMBoe from the divestiture of certain oil and gas properties within the Central Basin Platform. • Revision of previous estimates.
In 2024, we did not purchase any additional reserves. • Sales of minerals in place. In 2024, we sold 0.1 MMBoe from the divestiture of certain oil and gas properties within the Central Basin Platform. • Revision of previous estimates.
For the years ended December 31, 2024 2023 Oil (Bbl) Developed 56,106,714 56,029,039 Undeveloped 24,797,357 26,112,238 Total 80,904,071 82,141,277 Natural Gas (Mcf) Developed 102,538,111 99,896,022 Undeveloped 47,279,051 46,500,300 Total 149,817,162 146,396,322 Natural Gas Liquids (Bbl) Developed 19,426,387 15,449,907 Undeveloped 8,876,698 7,768,657 Total 28,303,085 23,218,564 Total (Boe) (1) Developed 92,622,787 88,128,284 Undeveloped 41,553,897 41,630,945 Total 134,176,684 129,759,229 (1) Six Mcf is deemed the equivalent of one Boe.
As of December 31, 2025 2024 2023 Oil (Bbl) Developed 60,108,129 56,106,714 56,029,039 Undeveloped 30,211,919 24,797,357 26,112,238 Total 90,320,048 80,904,071 82,141,277 Natural Gas (Mcf) Developed 121,424,006 102,538,111 99,896,022 Undeveloped 54,756,570 47,279,051 46,500,300 Total 176,180,576 149,817,162 146,396,322 Natural Gas Liquids (Bbl) Developed 23,453,484 19,426,387 15,449,907 Undeveloped 10,140,860 8,876,698 7,768,657 Total 33,594,344 28,303,085 23,218,564 Total (Boe) (1) Developed 103,798,946 92,622,787 88,128,284 Undeveloped 49,478,875 41,553,897 41,630,945 Total 153,277,821 134,176,684 129,759,229 (1) Six Mcf is deemed the equivalent of one Boe.
This consultation included review of properties, assumptions, and available data. Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report.
This data was reviewed by various levels of our management for completeness and accuracy before consultation with our independent reserve engineers. This consultation included review of properties, assumptions, and available data. Internal reserve estimates were compared to those prepared by CGA to test the estimates and conclusions before the reserves were included in this Annual Report.
Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs. We believe the Central Basin Platform leases contain additional potential drilling locations. Pursuing Profitable Acquisitions We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations.
We believe the Central Basin Platform leases contain additional potential drilling locations. Pursuing Profitable Acquisitions We have historically pursued acquisitions of properties that we believe to have exploitation and development potential comparable to our existing inventory of drilling locations.
Changes in Standardized Measure of Discounted Future Net Cash Flows 2024 2023 2022 Beginning of the year $ 1,399,185,191 $ 2,272,113,518 $ 1,137,364,848 Purchase of minerals in place — 141,738,066 996,313,882 Extensions, discoveries and improved recovery 226,741,618 57,607,609 20,447,842 Development costs incurred during the year 71,665,321 70,697,664 67,454,522 Sales of oil and gas produced, net of production costs (263,830,836) (266,004,598) (283,588,498) Sales of minerals in place (10,230,951) (59,600,128) — Accretion of discount 164,703,142 277,365,650 133,209,763 Net changes in price and production costs (285,618,955) (1,181,594,019) 646,819,172 Net change in estimated future development costs 6,732,428 37,865,811 (53,253,626) Revisions of previous quantity estimates (50,292,499) (187,443,783) 33,583,837 Changes in estimated timing of cash flows (44,073,556) (17,257,348) (119,428,019) Net change in income taxes 17,955,440 253,696,749 (306,810,205) End of the Year $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518 38 Table of Contents Our proved reserves by state as of December 31, 2024 are summarized in the table below.
Changes in Standardized Measure of Discounted Future Net Cash Flows 2025 2024 2023 Beginning of the year $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518 Purchase of minerals in place 174,287,315 — 141,738,066 Extensions, discoveries and improved recovery 98,831,276 226,741,618 57,607,609 Development costs incurred during the year 28,098,777 71,665,321 70,697,664 Sales of oil and gas produced, net of production costs (205,605,448) (263,830,836) (266,004,598) Sales of minerals in place — (10,230,951) (59,600,128) Accretion of discount 146,282,714 164,703,142 277,365,650 Net changes in price and production costs (372,012,158) (285,618,955) (1,181,594,019) Net change in estimated future development costs 28,456,200 6,732,428 37,865,811 Revisions of previous quantity estimates 17,046,040 (50,292,499) (187,443,783) Changes in estimated timing of cash flows (60,003,723) (44,073,556) (17,257,348) Net change in income taxes 35,175,996 17,955,440 253,696,749 End of the Year $ 1,123,493,332 $ 1,232,936,343 $ 1,399,185,191 39 Table of Contents Our proved reserves by state as of December 31, 2025 are summarized in the table below.
As of December 31, 2024, we owned interests in a total of 12,572 gross (8,722 net) developed acres and 14,979 gross (11,548 net) undeveloped acres with an average proved operated working interest of 91% and net revenue interest of 69%.
As of December 31, 2025, we owned interests in a total of 12,892 gross (8,833 net) developed acres and 8,370 gross (8,318 net) undeveloped acres with an average proved operated working interest of 92% and net revenue interest of 69%.
As of December 31, 2024, the Company had interests in approximately 581 gross vertical and 198 gross horizontal producing wells, of which we operate 470 vertical and 196 horizontal wells.
As of December 31, 2025, the Company had interests in approximately 509 gross vertical and 267 gross horizontal producing wells, of which we operate 401 vertical and 265 horizontal wells.
Years ended December 31, 2024 2023 2022 Average production costs (per Boe): Lease operating expenses $ 10.89 $ 10.61 $ 10.57 Gathering, transportation and processing costs $ 0.07 $ 0.07 $ 0.41 Ad valorem taxes (including methane tax) $ 1.12 $ 1.02 $ 1.04 Methane tax (2) $ 0.07 $ — $ — Ad valorem taxes (excluding methane tax) $ 1.05 $ 1.02 $ 1.04 Production taxes $ 2.24 $ 2.74 $ 3.80 (2) In accordance with the IRA, the EPA implemented a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds.
Years ended December 31, 2025 2024 2023 Average sales price: Oil (per Bbl) $ 63.53 $ 74.87 $ 76.21 Natural gas (per Mcf) $ (1.33) $ (1.44) $ 0.05 NGL (per Bbl) $ 6.43 $ 9.23 $ 11.95 Total (per Boe) $ 41.55 $ 50.94 $ 54.60 Years ended December 31, 2025 2024 2023 Average production costs (per Boe): Lease operating expenses $ 10.73 $ 10.89 $ 10.61 Gathering, transportation and processing costs $ 0.08 $ 0.07 $ 0.07 Ad valorem taxes (including methane tax) $ 1.07 $ 1.12 $ 1.02 Methane tax (1) $ (0.07) $ 0.07 $ — Ad valorem taxes (excluding methane tax) $ 1.14 $ 1.05 $ 1.02 Production taxes $ 1.94 $ 2.24 $ 2.74 (1) In accordance with the IRA, the EPA implemented a waste emission charge ("WEC") on methane emitted from applicable oil and gas facilities that exceed certain thresholds.
Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2024 2023 2022 Future cash inflows $ 6,165,487,616 $ 6,622,410,752 $ 9,871,961,000 Future production costs (2,432,555,200) (2,413,303,488) (2,751,896,250) Future development costs (1) (536,825,664) (562,063,424) (647,196,750) Future income taxes (465,768,645) (548,664,988) (1,142,147,641) Future net cash flows 2,730,338,107 3,098,378,852 5,330,720,359 10% annual discount for estimated timing of cash flows (1,497,401,764) (1,699,193,661) (3,058,606,841) Standardized Measure of Discounted Future Net Cash Flows $ 1,232,936,343 $ 1,399,185,191 $ 2,272,113,518 (1) Future development costs include not only development costs but also future asset retirement costs.
Standardized Measure of Discounted Future Net Cash Flows As of December 31, 2025 2024 2023 Future cash inflows $ 5,976,599,552 $ 6,165,487,616 $ 6,622,410,752 Future production costs (2,473,482,048) (2,432,555,200) (2,413,303,488) Future development costs (1) (573,423,296) (536,825,664) (562,063,424) Future income taxes (402,808,797) (465,768,645) (548,664,988) Future net cash flows 2,526,885,411 2,730,338,107 3,098,378,852 10% annual discount for estimated timing of cash flows (1,403,392,079) (1,497,401,764) (1,699,193,661) Standardized Measure of Discounted Future Net Cash Flows $ 1,123,493,332 $ 1,232,936,343 $ 1,399,185,191 (1) Future development costs include not only development costs but also future asset retirement costs.
Approximately $1,130.2 million pre-tax PV-10 and $952.6 million SMOG, respectively, of total proved reserves are associated with the PD reserves, which is approximately 77% of the total proved reserves’ pre-tax PV-10 value. The remaining $332.7 million pre-tax PV-10 and $280.4 million SMOG, respectively, are associated with PUD reserves.
Approximately $1,006.7 million pre-tax PV-10 and $858.0 million SMOG, respectively, of total proved reserves are associated with the PD reserves, which is approximately 76% of the total proved reserves’ pre-tax PV-10 value. The remaining $311.5 million pre-tax PV-10 and $265.5 million SMOG, respectively, are associated with PUD reserves.
As of December 31, 2024, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years of when they were initially disclosed.
Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves. As of December 31, 2025, no material amount of proved undeveloped reserves were not scheduled to be converted to proved developed status within five years of when they were initially disclosed.
The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy, and timeliness of annual independent reserves estimates. These independently developed reserves estimates are presented to the Audit Committee. In addition to reviewing the independently developed reserve reports, the Audit Committee also meets with CGA annually at a minimum.
The Corporate Reserves department works closely with independent reserve engineers from CGA at each fiscal year end to ensure the integrity, accuracy, and timeliness of annual independent reserves estimates.
In 2024, extensions of 12.8 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place. In 2024, we did not purchase any additional reserves. • Sales of minerals in place.
In 2025, extensions of 10.2 MMBoe were primarily the result of the successful operated drilling program in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place.
As of December 31, 2024, we owned interests in a total of 63,712 gross (56,620 net) developed acres and 6,336 gross (4,029 net) undeveloped acres with an average proved operated working interest of 97% and net revenue interest of 83% in the area.
As of December 31, 2025, we owned interests in a total of 84,193 gross (74,717 net) developed acres and 6,259 gross (4,366 net) undeveloped acres with an average proved operated working interest of 96% and net revenue interest of 81% in the area.
During the year ended December 31, 2024, we incurred costs of approximately $64.7 million to convert 33 properties from PUD to PD through development. These 33 properties produced 893 MBoe during the year ended December 31, 2024, and have reserves of 6,538 MBoe as of December 31, 2024. 39 Table of Contents • Extensions.
During the year ended December 31, 2025, we incurred costs of approximately $26.8 million to convert 14 properties from PUD to PD through development. These 14 properties produced 596 MBoe during the year ended December 31, 2025, and have reserves of 3.9 MMBoe as of December 31, 2025. • Extensions.
These wells were successful and there were no dry wells (1) . The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.
All wells were successful producing oil and gas in commercial quantities. 46 Table of Contents The table below contains information regarding the number of operated wells drilled and/or participated in during the periods indicated.
As of December 31, 2024, we owned interests in a total of 76,284 gross (65,342 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2024, we owned interests in approximately 21,315 gross (15,577 net) undeveloped acres.
As of December 31, 2025, we owned interests in a total of 97,085 gross (83,550 net) developed acres and operate the vast majority of our acreage position. In addition, as of December 31, 2025, we owned interests in approximately 14,629 gross (12,684 net) undeveloped acres.
The technologies and economic data used to estimate our proved reserves include, but are not limited to, well logs, geological maps, seismic data, well test data, production data, historical price and cost information, and property 40 Table of Contents ownership interests. This data was reviewed by various levels of our management for accuracy before consultation with our independent reserve engineers.
The technologies and economic data used to estimate our proved reserves include, but are not limited to, production data, historical price and cost information, and property ownership interests, and, to a lesser extent, geological maps, well logs, seismic data, and well test data.
Summary of Oil and Natural Gas Properties and Projects 41 Table of Contents Acreage The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2024 by region (net acreage is our percentage ownership of gross acreage).
These independently developed reserves estimates are presented to the Audit Committee, and the Audit Committee also meets with CGA annually at a minimum. 43 Table of Contents Summary of Oil and Natural Gas Properties and Projects Acreage The following table summarizes our gross and net developed and undeveloped acreage as of December 31, 2025 by region (net acreage is our percentage ownership of gross acreage).
The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows: Present value of estimated future net revenues (PV-10) $ 1,462,827,136 Future income taxes, discounted at 10% $ 229,890,793 Standardized measure of discounted future net cash flows $ 1,232,936,343 Reserve Quantity Information Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc.
PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP. 35 Table of Contents The table below provides a reconciliation of PV-10 to the standardized measure of discounted future net cash flows: Present value of estimated future net revenues (PV-10) $ 1,318,208,128 Future income taxes, discounted at 10% $ 194,714,796 Standardized measure of discounted future net cash flows $ 1,123,493,332 Reserve Quantity Information Our estimates of proved reserves and related valuations are based on reports independently determined and prepared by Cawley, Gillespie & Associates, Inc.
Oil Wells Gas wells Total Wells Gross Net Gross Net Gross Net 914 746 21 17 935 763 44 Table of Contents Drilling Activities During 2024, as operator, we drilled a total of 44.00 gross (43.94 net) wells.
Oil Wells Gas wells Total Wells Gross Net Gross Net Gross Net 899 742 20 16 919 758 Drilling Activities During 2025, as operator, we drilled a total of 18.00 gross (17.00 net) wells.
For the year ended December 31, 2024, we accrued for $527,687 in methane taxes within Ad valorem taxes in our Statements of Operations. The average oil sales price amounts above are calculated by dividing revenue from oil sales by the volume of oil sold, in Bbls.
For the year ended December 31, 2024, we accrued for $527,687 in methane taxes within Ad valorem taxes in our Statements of Operations. As the WEC was repealed by Congress on March 14, 2025, we reversed the methane tax accrual in the first quarter of 2025.
The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development. Our PUD reserves are part of a management adopted development plan that schedules PUD reserves to be developed within five years of initial disclosure as proved reserves.
In 2023, the negative revisions of prior reserves of 4.9 MMBoe consisted of 0.8 MMBoe (16%) related to changes in price and 4.1 MMBoe (84%) related to changes in performance and other economic factors. 41 Table of Contents The following table indicates projected reserves that we currently estimate will be converted from proved undeveloped to proved developed, as well as the estimated costs per year involved in such development.
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Central Basin Platform 63,712 56,620 6,336 4,029 70,048 60,649 Northwest Shelf 12,572 8,722 14,979 11,548 27,551 20,270 Total 76,284 65,342 21,315 15,577 97,599 80,919 Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary terms.
Developed Acreage Undeveloped Acreage Total Acreage Gross Net Gross Net Gross Net Central Basin Platform 84,193 74,717 6,259 4,366 90,452 79,083 Northwest Shelf 12,892 8,833 8,370 8,318 21,262 17,151 Total 97,085 83,550 14,629 12,684 111,714 96,234 Leases of undeveloped acreage will generally expire at the end of their respective primary terms unless production from such leasehold acreage has been established prior to expiration of such primary terms.
We believe the Northwest Shelf leases contain additional potential drilling locations. 33 Table of Contents Within the Central Basin Platform, we had a total of 176 proved undeveloped locations (13% horizontal and 88% vertical) and 217 PDNP opportunities based on the reserve report as of December 31, 2024.
Within the Central Basin Platform, we had a total of 214 proved undeveloped locations (29% horizontal and 71% vertical) and 236 PDNP opportunities based on the reserve report as of December 31, 2025. Our reserve estimates account for the capital costs required to develop these wells and the future plugging and abandonment costs.
For the year ended December 31, 2024 2023 2022 Gross Net Gross Net Gross Net Exploratory Productive — — — — — — Dry — — — — — — Development Productive — — 5.00 0.59 3.00 0.33 Dry — — — — — — Total Productive — — 5.00 0.59 3.00 0.33 Dry — — — — — — Present Activities We had one operated well waiting on completion as of December 31, 2024.
For the years ended December 31, 2025 2024 2023 Gross Net Gross Net Gross Net Exploratory Productive — — — — — — Dry — — — — — — Development Productive — — — — 5.00 0.59 Dry — — — — — — Total Productive — — — — 5.00 0.59 Dry — — — — — — Present Activities We had no wells in the process of being drilled or completed as of December 31, 2025. 47 Table of Contents Cost Information We conduct our oil and natural gas activities entirely in the United States.
Approximately 99.8% of our proved reserves are in the Permian Basin in Texas. Oil (Bbl) Natural Gas (Mcf) Natural Gas Liquids (Bbl) Total (Boe) (1) Pre-Tax PV-10 Value (2) Standardized Measure of Discounted Future Net Cash Flows 80,904,071 149,817,162 28,303,085 134,176,684 $ 1,462,827,136 $ 1,232,936,343 (1) Six Mcf is deemed the equivalent of one Boe.
Oil (Bbl) Natural Gas (Mcf) Natural Gas Liquids (Bbl) Total (Boe) (1) Pre-Tax PV-10 Value (2) Standardized Measure of Discounted Future Net Cash Flows 90,320,048 176,180,576 33,594,344 153,277,821 $ 1,318,208,128 $ 1,123,493,332 (1) Six Mcf is deemed the equivalent of one Boe. (2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.
Removed
(2) PV-10 is a non-GAAP financial measure. See below for a reconciliation.
Added
In 2025, extensions of 11.2 MMBoe were primarily the result of 41 newly added PUDs in addition to an active leasing program. Also impacting extensions were three successfully drilled wells in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place.
Removed
PV-10 is not a measure of financial or operational performance under GAAP, nor should it be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows as defined under GAAP.
Added
In 2025, the Company completed the acquisition of Lime Rock oil and gas leases and related property within Andrews County, as well as a few other minor acquisitions, that resulted in 14.0 MMBoe of additional reserves. • Sales of minerals in place. In 2025, the Company did not sell any reserves. • Revision of previous quantity estimates.
Removed
(2) At year-end 2022, we began reporting reserves on a three-stream basis, including NGLs separately from natural gas.
Added
In 2025, the positive revisions of prior reserves of 1.3 MMBoe consisted of a positive 7.2 MMBoe related to changes in performance and other economic factors, offset by a negative 5.9 MMBoe related to changes in price (including differentials and gathering related contract change that effects differentials).
Removed
Oil (Bbl) Gas (Mcf) NGL (Bbl) Total (Boe) % of Total Proved Pre-tax PV-10 (In thousands) Standardized Measure of Discounted Future Net Cash Flows (In thousands) Future Capital Expenditures (In thousands) Texas PD 55,923,366 102,194,638 19,356,935 92,312,741 69 % $ 1,126,097 $ 949,125 $ 149,138 PUD 24,797,357 47,279,051 8,876,698 41,553,897 31 % 332,654 280,376 378,175 Total Proved: 80,720,723 149,473,689 28,233,633 133,866,638 100 % $ 1,458,751 $ 1,229,501 $ 527,313 New Mexico PD 183,348 343,473 69,452 310,046 — % $ 4,076 $ 3,435 $ 98 PUD — — — — — % — — — Total Proved: 183,348 343,473 69,452 310,046 — % $ 4,076 $ 3,435 $ 98 Total PD 56,106,714 102,538,111 19,426,387 92,622,787 69 % $ 1,130,173 $ 952,561 $ 149,236 PUD 24,797,357 47,279,051 8,876,698 41,553,897 31 % 332,654 280,376 378,175 Total Proved: 80,904,071 149,817,162 28,303,085 134,176,684 100 % $ 1,462,827 $ 1,232,936 $ 527,411 Proved Reserves As of December 31, 2024, we had approximately 134.2 MMBoe of proved reserves, consisting of approximately 60% oil, 19% natural gas, and 21% NGLs, as summarized in the table above.
Added
Notable changes in proved reserves for the year ended December 31, 2023 included the following: • Extensions. In 2023, extensions of 4.8 MMBoe were primarily the result of the successful operated drilling program and non-operated activity in the Northwest Shelf and Central Basin Platform. • Purchase of minerals in place.
Removed
Estimated Costs Related to Conversion of Proved Undeveloped Reserves to Proved Developed Reserves Year Estimated Oil Reserves Developed (Bbl) Estimated Gas Reserves Developed (Mcf) Estimated NGL Reserves Developed (Bbl) Total Boe Estimated Development Costs 2025 9,654,298 6,533,610 1,631,662 12,374,895 $ 119,174,352 2026 6,405,076 12,440,141 2,262,321 10,740,754 101,542,200 2027 4,796,872 21,769,433 3,283,966 11,709,077 107,656,840 2028 3,941,111 6,535,867 1,698,749 6,729,171 44,293,536 2029 (1) 5,508,540 Total 24,797,357 47,279,051 8,876,698 41,553,897 $ 378,175,468 Preparation and Internal Controls Over Reserves Estimates All the proved oil and natural gas reserves disclosed in this Report are based on reserve estimates determined and prepared by our independent reserve engineers, Cawley, Gillespie & Associates, Inc.
Added
In 2023, the Company completed the acquisition of Founders oil and gas leases and related property within Ector County that resulted in 8.2 MMBoe in additional reserves. • Sales of minerals in place.
Removed
For periods prior to July 1, 2022, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Added
In 2023, the Company sold 5.7 MMBoe from the divestiture of the Delaware Basin assets (30%), the New Mexico operated assets (57%), and part of the Company's assets in Gaines County (13%). • Revision of previous quantity estimates.
Removed
(2) The Delaware Basin assets were sold with a closing date of May 11, 2023 and an effective date of March 1, 2023. 43 Table of Contents Production Prices and Production Costs The following tables provides historical pricing and costs statistics for the years ended December 31, 2024, 2023, and 2022.
Added
In 2023, the negative revisions of prior reserves of 9.0 MMBoe consisted of 5.3 MMBoe (59%) related to changes in price and 3.7 MMBoe (41%) related to changes in performance and other economic factors. 37 Table of Contents Our proved oil, natural gas, and natural gas liquid reserves are shown below.
Removed
Years ended December 31, 2024 2023 2022 Average sales price: Oil (per Bbl) $ 74.87 $ 76.21 $ 92.80 Natural gas (per Mcf) (1) $ (1.44) $ 0.05 $ 4.57 NGL (per Bbl) (1) $ 9.23 $ 11.95 $ 20.18 Total (per Boe) $ 50.94 $ 54.60 $ 76.95 (1) Due to our acquisition of Stronghold's assets, which reported its volumes and revenues on a three-stream basis, beginning July 1, 2022, we began reporting volumes and revenues on a three-stream basis, separately reporting crude oil, natural gas, and NGL sales.

… 13 more changes not shown on this page.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

2 edited+0 added−0 removed3 unchanged
Biggest changeItem 4: Mine Safety Disclosures Not applicable. PART II
Biggest changeItem 4: Mine Safety Disclosures Not applicable. 48 Table of Contents PART II
The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have concluded discovery in the matter and are currently set for trial in the first quarter of 2025.
The Company has filed an answer and a counterclaim denying the allegations and asserting affirmative defenses that would bar or substantially limit the plaintiff’s claims, asserting breach of contract and requesting a declaratory judgment and attorneys’ fees and costs. The parties have concluded discovery in the matter and are currently set for trial in the second quarter of 2026.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+1 added−1 removed1 unchanged
Biggest changeOur future dividend policy is within the discretion of our Board of Directors and will depend upon various factors, including our business, financial condition, results of operations, capital requirements, and investment opportunities. In addition, our credit facility contains provisions limiting our ability to pay dividends unless certain conditions are met.
Biggest changeWe currently intend to retain future earnings, if any, to pay down debt and finance the expansion of our business. Our future dividend policy is within the discretion of our Board and will depend upon various factors, including our business, financial condition, results of 49 Table of Contents operations, capital requirements, and investment opportunities.
Issuer Repurchases We did not make any repurchases of our equity securities during the year ended December 31, 2024. Item 6: Reserved 47 Table of Contents
Issuer Repurchases We did not make any repurchases of our equity securities during the year ended December 31, 2025. Item 6: Reserved 50 Table of Contents
Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities The information required by this item was disclosed and reported under Item 3.02, Unregistered Sales of Equity Securities, of our Form 8-K dated August 30, 2022, filed with the SEC on September 6, 2022 , which disclosure is incorporated herein by reference.
Recent Sales of Unregistered Securities and Use of Proceeds from Registered Securities The information required by this item was disclosed and reported under Item 3.02, Unregistered Sales of Equity Securities, of our Form 8-K dated March 31 , 2025 , filed with the SEC on April 4, 2025 , which disclosure is incorporated herein by reference.
This table is not intended to forecast future performance of our common stock. 46 Table of Contents The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated by reference.
The performance graph above is furnished and not filed for purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any registration statement filed under the Securities Act unless specifically identified therein as being incorporated by reference. The performance graph is not solicitation material subject to Regulation 14A of the Exchange Act.
The graph assumes the investment of $100 on December 31, 2019 in our common stock and each index and the reinvestment of all dividends, if any.
The graph assumes the investment of $100 on December 31, 2020 in our common stock and each index and the reinvestment of all dividends, if any. This table is not intended to forecast future performance of our common stock.
The performance graph is not solicitation material subject to Regulation 14A of the Exchange Act. Record Holders As of March 5, 2025, there were approximately 83 holders of record of our common stock. This is the number of record holders in the records of our transfer agent. It does not include holders of shares via brokerage accounts.
Record Holders As of March 4, 2026, there were approximately 73 holders of record of our common stock. This is the number of record holders in the records of our transfer agent. It does not include holders of shares via brokerage accounts. Dividend Policy We do not currently anticipate paying any cash dividends on our common stock.
Removed
Dividend Policy We do not currently anticipate paying any cash dividends on our common stock. We currently intend to retain future earnings, if any, to pay down debt and finance the expansion of our business.
Added
In addition, our credit facility contains provisions limiting our ability to pay dividends unless certain conditions are met.

Item 7. Management's Discussion & Analysis

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

67 edited+37 added−35 removed60 unchanged
Biggest changeThe table below sets forth our drilling and completion activities for 2024 by quarter, and full year total through December 31, 2024. 49 Table of Contents Quarter Area Wells Drilled Wells Completed Drilled Uncompleted ("DUC") (2) 1Q 2024 Northwest Shelf (Horizontal) 2 2 — Central Basin Platform (Horizontal) 3 3 — Central Basin Platform (Vertical) 6 6 — Total (1) 11 11 — 2Q 2024 Northwest Shelf (Horizontal) — — — Central Basin Platform (Horizontal) 5 5 — Central Basin Platform (Vertical) 6 6 — Total 11 11 — 3Q 2024 Northwest Shelf (Horizontal) 3 3 — Central Basin Platform (Horizontal) 4 2 2 Central Basin Platform (Vertical) 6 6 — Total 13 11 2 4Q 2024 Northwest Shelf (Horizontal) — — — Central Basin Platform (Horizontal) 5 6 1 Central Basin Platform (Vertical) 4 4 — Total 9 10 1 FY 2024 Northwest Shelf (Horizontal) 5 5 — Central Basin Platform (Horizontal) 17 16 1 Central Basin Platform (Vertical) 22 22 — Total (1) 44 43 1 (1) First quarter total and full year total do not include one SWD well completed in the Central Basin Platform (2) Note that the DUC wells represent period-end counts rather than period-to-date totals.
Biggest changeThe table below sets forth our drilling and completion activities for 2025 by quarter, and full year total through December 31, 2025. 52 Table of Contents Quarter Area Wells Drilled Wells Completed 1Q 2025 Northwest Shelf (Horizontal) 4 4 Central Basin Platform (Vertical) 3 3 Total 7 7 2Q 2025 Central Basin Platform (Horizontal) 1 1 Central Basin Platform (Vertical) 1 1 Total 2 2 3Q 2025 Central Basin Platform (Horizontal) 4 4 Central Basin Platform (Vertical) 1 1 Total 5 5 4Q 2025 Northwest Shelf (Horizontal) 1 1 Central Basin Platform (Horizontal) 2 2 Central Basin Platform (Vertical) 1 1 Total 4 4 FY 2025 Northwest Shelf (Horizontal) 5 5 Central Basin Platform (Horizontal) 7 7 Central Basin Platform (Vertical) 6 6 Total 18 18 (1) First quarter total and full year total do not include one SWD well completed in the Central Basin Platform (2) Note that the DUC wells represent period-end counts rather than period-to-date totals. 53 Table of Contents Market Conditions and Commodity Prices Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms.
Gain (loss) on disposal of assets increased $176,821 to a gain $89,693 in 2024 from a loss of $87,128 in 2023.
Gain (loss) on disposal of assets increased $176,821 to a gain of $89,693 in 2024 from a loss of $87,128 in 2023.
Ring’s executive team intends to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs. • Pursue strategic acquisitions with attractive upside potential.
Ring’s executive team intends to continue to utilize new and innovative technological advancements for completion optimization, comprehensive geological evaluation, and reservoir engineering analysis to generate value and to build future development opportunities. These technological advancements have led to a low-cost structure that helps maximize the returns generated by our drilling programs. • Pursue strategic acquisitions with attractive upside potential.
The Second Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas.
The Credit Agreement also contains other customary affirmative and negative covenants and events of default. The Company is required to maintain on a rolling 24 months basis, hedging transactions in respect of crude oil and natural gas, on not less than 50% of the projected production from its proved, developed, and producing oil and gas.
Average oil and natural gas prices received through 2024 continued to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
Average oil and natural gas prices received through 2024 and 2025 continued to demonstrate commodity price volatility and we believe oil and natural gas prices will continue to be volatile for the foreseeable future. The ability to find and develop sufficient amounts of crude oil and natural gas reserves at economical costs are critical to our long-term success.
Our total GTP costs increased by $48,760 to $506,333 in 2024 from $457,573 in 2023 and remained unchanged on a Boe basis to $0.07 in 2024 from $0.07 in 2023. The increase in costs was $30,298 from NGL processing costs and $18,462 from gas processing costs. Ad valorem taxes.
Our total GTP costs increased by $48,760 to $506,333 in 2024 from $457,573 in 2023 and remained unchanged on a Boe basis with $0.07 in 2024 and $0.07 in 2023. The increase in costs was $30,298 from NGL processing costs and $18,462 from gas processing costs. Ad valorem taxes.
The Second Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Second Credit Agreement) of 1.0 to 1.0.
The Credit Agreement contains certain covenants, which, among other things, require the maintenance of (i) a total Leverage Ratio of not more than 3.0 to 1.0 and (ii) a minimum ratio of Current Assets to Current Liabilities (as such terms are defined in the Credit Agreement) of 1.0 to 1.0.
LOE increased due to the full year of expenses from the assets acquired with the Founders Acquisition (closed in August 2023) which contributed to a 9% increase in production of 577,733 Boe year-over-year.
LOE increased due to the full year of expenses from the assets acquired with the Founders Acquisition (closed in August 2023) which contributed to a 9% increase in production of 577,733 Boe.
Our estimates of reserves and future cash flow as of December 31, 2024 and 2023 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2024 and 2023, respectively, in accordance with SEC guidelines.
Our estimates of reserves and future cash flow as of December 31, 2025 and 2024 were prepared using an average price equal to the unweighted arithmetic average of the first day of the month price for each month within the 12-month periods ended December 31, 2025 and 2024, respectively, in accordance with SEC guidelines.
The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Second Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 0.00% per annum, plus (b) a margin between 2.0% and 3.0% per annum (depending on the then-current level of borrowing base usage).
The annual interest rate on each base rate loan is (a) the greatest of (i) the Administrative Agent’s prime lending rate, (ii) the Federal Funds Rate (as defined in the Credit Agreement) plus 0.5% per annum, (iii) the adjusted term SOFR determined on a daily basis for an interest period of one month, plus 1.00% per annum and (iv) 1.00% per annum, plus (b) a margin between 1.75% and 2.75% per annum (depending on the then-current level of borrowing base usage).
If these depressed or inverted natural gas prices return to the region, our natural gas revenues will continue to be negatively impacted. Inflation Inflation has increased costs associated with our capital program and production operations.
If these depressed or inverted natural gas prices continue in the region, our natural gas revenues will continue to be negatively impacted. Inflation Inflation has increased costs associated with our capital program and production operations.
The oil sales increased by a volume variance of approximately $21.5 million from an increase in sales volumes to 4,861,628 barrels of oil in 2024 from 4,579,942 barrels of oil in 2023, primarily driven by production from wells within the 52 Table of Contents assets acquired with the Founders Acquisition (closed in August 2023).
The oil sales increased by a volume variance of approximately $21.5 million from an increase in sales volumes to 4,861,628 barrels of oil in 2024 from 4,579,942 barrels of oil in 2023, primarily driven by production from wells within the assets acquired with the Founders Acquisition (closed in August 2023).
Additionally, depletion experienced a price variance of $2.2 million, from a higher depletion expense per unit overall year over year, due to an 18.9 million increase in average estimated costs of property coupled with a 1.6 million reduction in the amortization base (Boe).
Additionally, depletion experienced a price variance of $2.2 million, from a higher depletion expense per unit overall year over year, due to an $18.9 million increase in average estimated costs of 58 Table of Contents property coupled with a 1.6 million reduction in the amortization base (Boe).
However, if the borrowing base utilization is less than 25% at the hedge testing date and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
However, on any hedge testing date, (a) if the borrowing base utilization is less than 25% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 0% from such hedge testing date to the next succeeding hedge testing date and (b) if the borrowing base utilization percentage is equal to or greater than 25%, but less than 50% and the Leverage Ratio is not greater than 1.25 to 1.00, the required hedging percentage for months 13 through 24 of the rolling 24 month period provided for will be 25% from such hedge testing date to the next succeeding hedge testing date.
The increase was primarily the result of the Company recognizing a gain on disposal of assets primarily from selling multiple leased vehicles during 2024, as opposed to a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023. Other income. Other income decreased $92,279 to $106,656 in 2024 from $198,935 in 2023.
The increase was primarily the result of the Company recognizing a gain on disposal of assets from selling multiple leased vehicles during 2024, compared with a loss on disposal of assets primarily from selling multiple company owned vehicles during 2023. Other income. Other income decreased $92,279 to $106,656 in 2024 from $198,935 in 2023.
Our average depreciation, depletion and amortization per Boe increased to $13.73 per Boe during 2024 from $13.40 per Boe during 2023. 53 Table of Contents Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion decreased by $45,388 to $1,380,298 in 2024 from $1,425,686 in 2023.
Our average depreciation, depletion and amortization per Boe increased to $13.73 per Boe during 2024 from $13.40 per Boe during 2023. Asset retirement obligation accretion. Our asset retirement obligation (“ARO”) accretion decreased by $45,388 to $1,380,298 in 2024 from $1,425,686 in 2023.
Also, the Second Credit Agreement permits the Company to declare dividends for its equity owners, subject to certain limitations, including (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, taxes, depreciation and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Second Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Second Credit Agreement) is not greater than 80%.
The Credit Agreement permits the Company to declare restricted payments (including dividends) for its equity owners, subject to certain limitations, including (a) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio (outstanding debt to adjusted earnings before interest, income tax expense, depreciation, depletion and amortization, exploration expenses, and all other non-cash charges acceptable to the Administrative Agent) does not exceed 2.00 to 1.00, (iii) the amount of such payments does not exceed Available Free Cash Flow (as defined in the Credit Agreement), and (iv) the Borrowing Base Utilization Percentage (as defined in the Credit Agreement) is not greater than 80%; or (b) (i) no default or event of default has occurred or will occur upon such payments, (ii) the pro forma Leverage Ratio does not exceed 1.50 to 1.00, and (iii) the Borrowing Base Utilization Percentage is not greater than 75%.
During the three months ended December 31, 2024, the Company made net paydowns of $7 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $385 million. • Employ industry leading drilling and completion techniques .
During the three months ended December 31, 2025, the Company made net paydowns of $8 million on its revolving line of credit, resulting in the outstanding long-term debt balance of $420 million. • Employ industry leading drilling and completion techniques .
Off-Balance Sheet Financing Arrangements As of December 31, 2024, we had no off-balance sheet financing arrangements. 58 Table of Contents Critical Accounting Policies and Estimates Our discussion of financial condition and results of operations is based upon the information reported in our financial statements.
Off-Balance Sheet Financing Arrangements As of December 31, 2025, the Company had no off-balance sheet financing arrangements. 61 Table of Contents Critical Accounting Policies and Estimates Our discussion of financial condition and results of operations is based upon the information reported in our financial statements.
As of December 31, 2024, we had cash on hand of $1.9 million and negative working capital of $54.6 million, compared to cash on hand of $0.3 million and negative working capital of $57.9 million as of December 31, 2023 and cash on hand of $3.7 million and negative working capital of $78.6 million as of December 31, 2022.
As of December 31, 2025, we had cash on hand of $0.9 million and negative working capital of $38.9 million, compared to cash on hand of $1.9 million and negative working capital of $54.6 million as of December 31, 2024 and cash on hand of $0.3 million and negative working capital of $57.9 million as of December 31, 2023.
As of December 31, 2024 and 2023, the Company did not carry a valuation allowance against its federal and state deferred tax assets.
As of December 31, 2025 and 2024, the Company did not carry a valuation allowance against its federal and state deferred tax assets. 63 Table of Contents
As of December 31, 2023, our reserves were based on an SEC average price of $74.70 per Bbl of WTI oil posted and $2.637 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines. Income Taxes.
As of December 31, 2024, our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil 62 Table of Contents posted and $2.130 per MMBtu Henry Hub natural gas. Prices are adjusted by local field and lease level differentials and are held constant for life of reserves in accordance with SEC guidelines.
General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $2.1 million to $29.2 million in 2023 from $27.1 million in 2022.
General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $0.5 million to $29.6 million in 2024 from $29.2 million in 2023.
We continually make revisions to reserve estimates throughout the year as additional properties are acquired. We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
We make changes to depletion rates and impairment calculations in the same period that changes to the reserve estimates are made.
This change of $29.1 million in unrealized derivatives was from $31.1 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, offset by $1.9 million unfavorable changes to the marked-to-market natural gas derivative contract balance. Loss on disposal of assets.
This change of approximately $23.4 million in unrealized derivatives was from $16.5 million in favorable derivative portfolio changes and futures pricing for marked-to-market oil derivative contracts, as well as $6.9 million favorable changes to the marked-to-market natural gas derivative contract balance. Gain (loss) on disposal of assets.
We have experienced increases in the costs of many of the materials, supplies, equipment, and services used in our operations and we expect inflation to continue based on current economic circumstances. In addition, the attempts to reduce inflation by the U.S.
We have experienced increases in the costs of many of the materials, supplies, equipment, and services used in our operations and we expect inflation to continue based on current economic circumstances, including tariffs, trade wars, and supply chain disruptions.
We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible. 51 Table of Contents Results of Operations The following table sets forth selected operating data for the periods indicated: For the years ended December 31, 2024 2023 2022 Net production: Oil (Bbls) 4,861,628 4,579,942 3,459,840 Natural gas (Mcf) 6,423,674 6,339,158 4,088,642 Natural gas liquids (Bbls) 1,258,814 976,852 371,329 Net sales: Oil $ 363,971,394 $ 349,044,863 $ 321,062,672 Natural gas (9,265,335) 334,175 18,693,631 Natural gas liquids 11,621,355 11,676,963 7,493,234 Average sales price: Oil (per Bbl) $ 74.87 $ 76.21 $ 92.80 Natural gas (per Mcf) (1.44) 0.05 4.57 Natural gas liquids (Bbl) 9.23 11.95 20.18 Production costs and expenses: Lease operating expenses $ 78,310,949 $ 70,158,227 $ 47,695,351 Gathering, transportation and processing costs 506,333 457,573 1,830,024 Ad valorem taxes 8,069,064 6,757,841 4,670,617 Oil and natural gas production taxes 16,116,565 18,135,336 17,125,982 Other costs and operating expenses: Depreciation, depletion and amortization $ 98,702,843 $ 88,610,291 $ 55,740,767 Asset retirement obligation accretion 1,380,298 1,425,686 983,432 Operating lease expense 700,362 541,801 363,908 General and administrative expense ("G&A") 29,640,300 29,188,755 27,095,323 Share-based compensation 5,506,017 8,833,425 7,162,231 G&A excluding share-based compensation 24,134,283 20,355,330 19,933,092 Other income (expense): Interest income $ 491,946 $ 257,155 $ 4 Interest (expense) (43,311,810) (43,926,732) (23,167,729) Gain (loss) on derivative contracts (2,365,917) 2,767,162 (21,532,659) Gain (loss) on disposal of assets 89,693 (87,128) — Other income 106,656 198,935 — Provision for Income Taxes $ (20,440,954) $ (125,242) $ (8,408,724) Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 Oil sales .
We continue to closely monitor costs and take all reasonable steps to mitigate the inflationary effect on our cost structure and also work to enhance our efficiency to minimize additional cost increases where possible. 54 Table of Contents Results of Operations For the years ended December 31, 2025 2024 2023 Net production: Oil (Bbls) 4,841,164 4,861,628 4,579,942 Natural gas (Mcf) 6,980,958 6,423,674 6,339,158 Natural gas liquids (Bbls) 1,387,818 1,258,814 976,852 Net sales: Oil $ 307,553,614 $ 363,971,394 $ 349,044,863 Natural gas (9,297,614) (9,265,335) 334,175 Natural gas liquids 8,922,072 11,621,355 11,676,963 Average sales price: Oil (per Bbl) $ 63.53 $ 74.87 $ 76.21 Natural gas (per Mcf) (1.33) (1.44) 0.05 Natural gas liquids (Bbl) 6.43 9.23 11.95 Production costs and expenses: Lease operating expenses $ 79,353,806 $ 78,310,949 $ 70,158,227 Gathering, transportation and processing costs 585,087 506,333 457,573 Ad valorem taxes 7,906,586 8,069,064 6,757,841 Oil and natural gas production taxes 14,312,232 16,116,565 18,135,336 Other costs and operating expenses: Depreciation, depletion and amortization $ 96,414,150 $ 98,702,843 $ 88,610,291 Ceiling test impairment 108,825,446 — — Asset retirement obligation accretion 1,490,255 1,380,298 1,425,686 Operating lease expense 700,362 700,362 541,801 General and administrative expense ("G&A") 31,928,576 29,640,300 29,188,755 Share-based compensation 6,135,957 5,506,017 8,833,425 G&A excluding share-based compensation 25,792,619 24,134,283 20,355,330 Other income (expense): Interest income $ 290,879 $ 491,946 $ 257,155 Interest (expense) (40,430,929) (43,311,810) (43,926,732) Gain (loss) on derivative contracts 31,658,839 (2,365,917) 2,767,162 Gain (loss) on disposal of assets 446,400 89,693 (87,128) Other income 189,294 106,656 198,935 Benefit from (Provision for) Income Taxes $ 7,452,746 $ (20,440,954) $ (125,242) Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 Oil sales .
As of December 31, 2024, 59 Table of Contents our reserves were based on an SEC average price of $71.96 per Bbl of WTI oil posted and $2.130 per MMBtu Henry Hub natural gas.
As of December 31, 2025, our reserves were based on an SEC average price of $61.82 per Bbl of WTI oil posted and $3.387 per MMBtu Henry Hub natural gas.
The interest rate on each SOFR Loan will be the adjusted term SOFR for the applicable interest period plus a margin between 3.0% and 4.0% (depending on the then-current level of borrowing base usage).
The reference rate in the Credit Agreement is the Secured Overnight Financing Rate ("SOFR"). The interest rate on each SOFR Loan will (i) be the adjusted term SOFR for the applicable interest period plus (ii) a margin between 2.75% and 3.75% (depending on the then-current level of borrowing base usage) plus (iii) a 0.10% SOFR adjustment.
Our primary source of cash in 2024 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures and pay down our debt balance.
Our primary source of cash in 2025 was from funds generated from the sale of oil and natural gas production. These cash flows were primarily used to fund our capital expenditures and pay down our debt balance. We believe the combination of the sources of capital discussed will continue to be adequate to meet our short and long-term liquidity needs.
Meanwhile, in the Central Basin Platform, the Company drilled and completed six vertical wells, all with a working interest of 100%, three in Ector County and three in Crane County. Finally, in the Central Basin Platform in Andrews County, the Company drilled four 1-mile horizontal wells, all with a working interest of 100%. Two of these wells were completed.
The Company drilled and completed two additional 1-mile horizontal wells in the Central Basin Platform, one in Andrews County and one in Crane County (both with a working interest of 100%). Also in Crane County the Company drilled and completed one vertical well (with a working interest of 100%).
Natural Gas Takeaway Capacity The Permian Basin has been experiencing a lack of sufficient pipeline transportation that is connected to markets that are purchasing the natural gas produced. This has resulted in negative natural gas prices at times, whereby the seller is 50 Table of Contents actually paying the purchaser to take the gas.
Natural Gas Takeaway Capacity The Permian Basin has been experiencing a lack of sufficient pipeline transportation for its natural gas production. This has resulted in negative natural gas prices at times, whereby the seller is actually paying the purchaser to take the gas. We experienced negative realized gas prices for all of 2024 and 2025 and conditions are continuing.
On the southern side of the Central Basin Platform, the Company drilled and completed one vertical well in its Crane County acreage and three vertical wells in its Ector County acreage (each with a working interest of 100%).
In the third quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed three 1-mile horizontal wells, each with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one 1-mile horizontal well and one vertical well, both with a working interest of 100%.
This was offset by additional ARO accretion from wells acquired in the Founders Acquisition, which closed in August 2023, as well as new wells drilled in 2024. Operating lease expense.
This was offset by additional ARO accretion from wells acquired in the Founders Acquisition, which closed in August 2023, as well as new wells drilled in 2024. Operating lease expense. Our operating lease expense increased by $158,561 to $700,362 in 2024 from $541,801 in 2023 due to additional office space leased in The Woodlands office, substantially completed in September 2023.
The borrowing base is redetermined semi-annually each May and November. The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions. Rather than Eurodollar loans, the reference rate in the Second Credit Agreement is the SOFR.
The borrowing base is subject to reduction in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company and cancellation of certain hedging positions.
During the third quarter of 2024, in the Northwest Shelf in Yoakum County, the Company drilled and completed two 1-mile horizontal wells, each with a working interest of 100%, and one 1.5-mile horizontal well with a working interest of approximately 94.2%.
Finally, the Company began drilling one 1.5-mile horizontal well (with a working interest of 100%) in the Northwest Shelf in Yoakum County. In the fourth quarter of 2025, the Company finished drilling and completed the aforementioned 1.5-mile horizontal well in the Northwest Shelf.
Additionally, during 2024, 2023 and 2022, we used cash of $170.0 million, $215.0 million and $511.0 million, respectively, to reduce the outstanding balance on our Credit Facility.
We used cash to fund our capital expenditures and development aggregating $571.2 million over the three years ended December 31, 2025. Additionally, during 2025, 2024 and 2023, we used cash of $196.8 million, $170.0 million and $215.0 million, respectively, to reduce the outstanding balance on our Credit Facility.
The accuracy of our reserve estimates is a function of: • the quality and quantity of available data; • the interpretation of that data; • the accuracy of various mandated economic assumptions; and • the judgments of the persons preparing the estimates.
The accuracy of our reserve estimates is a function of: the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgments of the persons preparing the estimates. Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers.
Our total lease operating expenses (“LOE”) increased approximately $22.5 million to $70.2 million in 2023 from $47.7 million in 2022 and increased slightly on a Boe basis to $10.61 in 2023 from $10.57 in 2022. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe.
Our total lease operating expenses (“LOE”) increased approximately $1.0 million to $79.4 million in 2025 from $78.3 million in 2024 and decreased on a Boe basis to $10.73 in 2025 from $10.89 in 2024. These per Boe amounts are calculated by dividing our total LOE by our total volume sold, in Boe.
Additionally, within the Central Basin Platform, the Company drilled and completed one salt water disposal ("SWD") well in Crane County. In the second quarter of 2024, in the Central Basin Platform, the Company drilled and completed eleven wells, all with a working interest of 100%.
In the second quarter of 2025, in the Central Basin Platform in Andrews County, the Company drilled and completed one 1-mile horizontal well, with a working interest of 100%. Also in the Central Basin Platform in Crane County, the Company drilled and completed one vertical well, with a working interest of 100%.
As of December 31, 2024, $385 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Second Credit Agreement. Equity Offering.
As of December 31, 2025, $420 million was outstanding on the Credit Facility and the Company was in compliance with all covenants in the Credit Agreement. Cash Flows. Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility.
A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling. The Company did not have any write-downs related to the full cost ceiling limitation during the years ended December 31, 2024, 2023, or 2022.
A write-down may not be reversed in future periods even though higher oil and natural gas prices may subsequently increase the ceiling.
During 2024, 2023, and 2022, the Company had a net repayment of $40.0 million, a net draw of $10.0 million, and a net draw of $125.0 million on the Credit Facility, respectively. We used cash to fund our capital expenditures and development aggregating $700.3 million over the three years ended December 31, 2024.
During the three years ended December 31, 2025, we financed $12.3 million through proceeds from the sale of common stock. During 2025, 2024, and 2023, the Company had a 60 Table of Contents net draw of $35.0 million, a net repayment of $40.0 million, and a net draw of $10.0 million on the Credit Facility, respectively.
Our proved reserve information included in this Annual Report was prepared and determined by Cawley, Gillespie & Associates, Inc., independent petroleum engineers. Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered.
Because these estimates depend on many assumptions, all of which may differ substantially from actual results, reserve estimates may be different from the quantities of oil and natural gas that are ultimately recovered. We continually make revisions to reserve estimates throughout the year as additional properties are acquired.
Also in Crane County the Company drilled three 1-mile horizontal wells (each with a working interest of 100%), completing the first two in the fourth quarter, and the last well will be completed in 2025. In summary, for 2024, the Company drilled 22 horizontal wells, 22 vertical wells, and one SWD well, completing all but one horizontal well.
Drilling and Completion In the first quarter of 2025, in the Northwest Shelf in Yoakum County, the Company drilled and completed three 1-mile horizontal wells and one 1.25-mile horizontal well, all with a working interest of 75%. In the Central Basin Platform in Ector County, the Company drilled and completed three vertical wells, all with a working interest of 100%.
The increase was primarily related to a $2.2 million increase in salaries, wages, and bonuses, a $1.7 million increase in share-based compensation, $0.6 million in additional legal fees, $0.5 million in higher software costs, $0.1 million in engineering costs, and $0.1 million in accounting, tax, and audit fees.
The increase was primarily related to an increase of $2.5 million in salaries, wages, and bonuses, $0.6 million in share-based compensation, and $0.6 million in other professional fees. This was offset by reductions of $0.5 million in environmental sustainability costs, $0.5 million in legal fees, $0.4 million in additional costs capitalized, and $0.1 million in credit loss expense. Interest income.
On February 12, 2024, the Company, Truist Bank as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into an amendment (the "Amendment") to the Second Credit Agreement.
A. as the Administrative Agent and Issuing Bank (“Bank of America”), and the lenders party thereto (the “Lenders”) entered into the Third Amended and Restated Credit Agreement (the “Credit Agreement”) which amended and restated that certain Second Amended and Restated Credit Agreement dated as of August 31, 2022, by and among the Company, Truist Bank, as administrative agent, and the lenders party thereto, as amended by that certain First Amendment to Second Amended and Restated Credit Agreement, dated as of February 12, 2024 (the “Existing Credit Agreement”).
Gain (loss) on derivative contracts. During 2023, the Company incurred a gain on derivative contracts of approximately $2.8 million. During 2022, the Company recorded a loss on derivative contracts of approximately $21.5 million. For the derivative contract settlements, the Company recorded a realized loss of $9.1 million during 2023 and a realized loss of $62.5 million during 2022.
For the derivative contract settlements, the Company recorded a realized gain of $5.5 million during 2025 and a realized loss of $5.2 million during 2024. The change of approximately $10.6 million in the realized derivative settlements was $14.1 million from realized oil derivative settlements and $(3.5) million from realized natural gas derivative settlements.
This was offset by increased oil and NGL revenues in addition to a more favorable derivative contract portfolio in comparison with the year-end commodity futures prices. Liquidity and Capital Resources Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock.
The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company. 59 Table of Contents Liquidity and Capital Resources Financing of Operations. We have historically funded our operations through cash available from operations and from equity offerings of our stock.
In 2022, the average gross realized price for natural gas was $6.32 per Mcf, and the average fees per Mcf were $(1.75), bringing the net average price to $4.57 per Mcf. This was partially offset by a volume variance of approximately $10.3 million as the volume increased to 6,339,158 Mcf in 2023 from 4,088,642 Mcf in 2022. NGL sales.
In 2024, the average gross realized price for natural gas was $0.29 per Mcf, and the average fees per Mcf were $(1.73), bringing the net average price to (1.44) per Mcf. The natural gas sales volume increased to 6,980,958 Mcf in 2025 from 6,423,674 Mcf in 2024. NGL sales.
The Midland office lease was amended effective October 1, 2022, with the revised five-year lease ending September 30, 2027. The Company has financing leases for vehicles with varying maturity dates through 2027. Future lease payments for financing leases aggregate $1,667,763.
Future lease payments for operating leases aggregate $1,497,380. The Company has financing leases for vehicles with varying maturity dates through 2028. Future lease payments for financing leases aggregate $1,428,999.
The significant reduction in realized natural gas prices was driven by a lower market index price. In 2023, the average gross realized price for natural gas was $1.67 per Mcf, and the average fees per Mcf were $(1.62), bringing the net average price to $0.05 per Mcf.
The positive change in price was due to an increase in the average gross realized price that was higher than the increase in the average fees. In 2025, the average gross realized price for natural gas was $0.75 per Mcf, and the average fees per Mcf were $(2.08), bringing the net average price to $(1.33) per Mcf.
Offsetting this increase to sales was a negative price variance of approximately $8.0 million, as the average realized price per barrel of NGLs was $11.95 in 2023 compared to $20.18 in 2022. Lease operating expenses.
NGL sales decreased approximately $2.7 million to $8.9 million in 2025 from $11.6 million in 2024, due to a price variance of approximately $(3.9) million, as the average realized price per barrel of NGLs was $6.43 in 2025 compared to $9.23 in 2024.
Our operating lease expense increased by $158,561 to $700,362 in 2024 from $541,801 in 2023 due to additional office space leased in The Woodlands office, which was substantially completed in September 2023. General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $0.5 million to $29.6 million in 2024 from $29.2 million in 2023.
Operating lease expense. Our operating lease expense was consistent year over year, as the Company experienced no changes in its office leases. General and administrative expenses (including share-based compensation) . General and administrative expenses increased approximately $2.3 million to $31.9 million in 2025 from $29.6 million in 2024.
On July 1, 2014, the Company entered into a Credit Agreement with SunTrust Bank (now Truist Bank), as lender, issuing bank and administrative agent for several banks and other financial institutions and lenders (the “Administrative Agent”), (which was amended several times) that provided for a maximum borrowing base of $1 billion with security consisting of substantially all of the assets of the Company.
On June 18, 2025, the Company, as borrower, Bank of America, N.A. as the Administrative Agent and Issuing Bank, and the lenders party thereto (the "Lenders") entered into that certain Third Amended and Restated Credit Agreement (the "Credit Agreement"), with a maximum borrowing base of $1 billion secured by substantially all of the assets of the Company and a maturity date of June 2029.
Our total ad valorem taxes increased approximately $2.1 million to $6.8 million in 2023 from $4.7 million in 2022 and decreased on a Boe basis to $1.02 in 2023 from $1.04 in 2022. Ad valorem taxes increased due to a full year of taxes for the properties within counties acquired in the Stronghold Acquisition (i.e.
Our total ad valorem taxes decreased approximately $0.2 million to $7.9 million in 2025 from $8.1 million in 2024 and decreased on a Boe basis to $1.07 in 2025 from $1.12 in 2024.
Among other things, the Amendment amends the definition of Free Cash Flow so amounts used by the Company for acquisitions will no longer be subtracted from the calculation of Free Cash Flow. The Second Credit Agreement has a borrowing base of $600 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time.
The Credit Agreement has a borrowing base of $585 million, which is subject to periodic redeterminations, mandatory reductions and further adjustments from time to time. The borrowing base is redetermined semi-annually each May and November.
The Woodlands office was under a five-and-a-half-year lease beginning January 15, 2021; however, effective as of May 31, 2023, The Woodlands office sub-lease was terminated. On May 9, 2023, the Company entered into a 71-month (five years and 11-month) new lease for a larger amount of office space in The Woodlands, Texas.
The Company leases office spaces in The Woodlands, Texas and Midland, Texas. The Woodlands office is currently under a 71-month (five years and 11-month) lease for its office space, effective May 9, 2023. The Midland office is currently under a five-year lease for its office space, effective October 1, 2022 and ending September 30, 2027.
Contractual Obligations. The Company maintains a Credit Facility which currently has a $600 million borrowing base. The outstanding balance on that Credit Facility as of December 31, 2024 was $385 million, which will require repayment or refinancing at or prior to maturity in August 2026. The Company leases office spaces in The Woodlands, Texas and Midland, Texas.
The outstanding balance on that Credit Facility as of December 31, 2025 was $420 million, which will require repayment or refinancing at or prior to maturity in June 2029. Refer to "NOTE 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Credit Facility.
The 2024 income tax provision was a significant change from year to year impacting the overall decrease in net income realized by the Company. 54 Table of Contents Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 Oil sales . Oil sales increased approximately $28.0 million to $349.0 million in 2023 from $321.1 million in 2022.
Lessening this impact was the gain on derivative contracts, which was positive in terms of both unrealized and realized gains. 57 Table of Contents Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 Oil sales . Oil sales increased approximately $14.9 million to $364.0 million in 2024 from $349.0 million in 2023.
The decrease of $53.4 million in the realized loss was $50.5 million from realized oil derivative settlements and $2.9 million from realized natural gas derivative settlements. For the marked-to-market contracts, the Company recorded an unrealized gain of $11.9 million during 2023 and an unrealized gain of $41.0 million during 2022.
For the marked-to-market contracts, the Company recorded an unrealized gain of $26.2 million during 2025 and an unrealized gain of $2.8 million during 2024.
Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. 2024 Developments and Highlights Drilling and Completion In the first quarter of 2024, in the Northwest Shelf, the Company drilled and completed two 1-mile horizontal wells (one with a working interest of 99.5% and the other with a working interest of 100%).
Our executive team, with its extensive experience in the Permian Basin, has many relationships with operators and service providers in the region. 51 Table of Contents 2025 Developments and Highlights Lime Rock Acquisition On March 31, 2025, the Company, as buyer, and Lime Rock Resources IV-A, L.P. (“LRRA”), and Lime Rock Resources IV-C, L.P.
Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 5.02% in 2023 from 4.93% during 2022. Overall, the percentage was consistent year over year. Depreciation, depletion and amortization .
Oil and natural gas production taxes . Oil and natural gas production taxes as a percentage of oil and natural gas sales increased to 4.66% in 2025 from 4.40% during 2024. In 2024, an accrual of $1.2 million was made for estimated severance tax refunds expected, which lowered the average rate for 2024.
Natural gas sales decreased approximately $18.4 million to $0.3 million in 2023 from $18.7 million in 2022. The natural gas sales decreased by a negative price variance of approximately $28.6 million, as the average realized per Mcf gas price decreased to $0.05 in 2023 from $4.57 in 2022.
Oil sales decreased approximately $56.4 million to $307.6 million in 2025 from $364.0 million in 2024. This was due to a price variance of approximately $(54.9) million from a decrease in the average realized per barrel oil price to $63.53 in 2025 from $74.87 in 2024.
Historically, primary sources of cash have been from operations, equity offerings and borrowings on the Credit Facility. During 2024, 2023, and 2022 we had net cash provided by operating activities of $194.4 million, $198.2 million, and $197.0 million, respectively. During the three years ended December 31, 2024, we financed $20.5 million through proceeds from the sale of common stock.
During 2025, 2024, and 2023 we had net cash provided by operating activities of $150.8 million, $194.4 million, and $198.2 million, respectively.
Specifically, in our Andrews County acreage the Company drilled and completed five 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.
In summary, for 2025, the Company drilled and completed 12 horizontal wells and 6 vertical wells.
Other impacts to revenue volumes include organic growth from workovers, new drills, and other capital expenditures, offset by divestitures completed. The volume variance was offset by a negative price variance of approximately $76.0 million from a decrease in the average realized per barrel oil price to $76.21 in 2023 from $92.80 in 2022. Natural gas sales.
Also impacting the oil sales was a volume variance of approximately $(1.5) million from a decrease in sales volumes to 4,841,164 barrels of oil in 2025 from 4,861,628 barrels of oil in 2024, 55 Table of Contents primarily driven by natural asset decline, offset by production from wells within the assets acquired with the Lime Rock Acquisition (closed in March 2025) and organic growth from workovers, new drills, and other capital expenditures.
Removed
In the Central Basin Platform, the Company drilled and completed nine wells, all with a working interest of 100%.
Added
(“LRRC” and with LRRA, “Lime Rock”), as seller, consummated the transactions contemplated in that certain Purchase and Sale Agreement dated February 25, 2025, by and among the Company, LRRA and LRRC (the “Purchase Agreement”) that was previously reported on Form 8-K filed on February 28, 2025 with the Securities and Exchange Commission (“SEC”).
Removed
Specifically, in our Andrews County 48 Table of Contents acreage the Company drilled and completed three 1-mile horizontal wells, in the Ector County acreage the Company drilled three vertical wells, and in the Crane County acreage the Company drilled and completed three vertical wells.
Added
At the closing of the Purchase Agreement, among other things, the Company acquired (the “Lime Rock Acquisition”) interests in oil and gas leases and related property of Lime Rock located in Andrews County, Texas, for an aggregate consideration consisting of: (i) approximately $69.3 million in cash, net of customary purchase price adjustments, paid at the closing of the Lime Rock Acquisition, (ii) $10.0 million in cash paid on December 31, 2025, and (iii) 6,452,879 shares of common stock (the "LRR Shares").
Removed
The remaining two wells were completed in the fourth quarter of 2024. In the fourth quarter of 2024, the Company completed and placed on production the two aforementioned 1-mile horizontal wells in the Central Basin Platform. The Company completed two additional 1-mile horizontal wells in the Central Basin Platform in Andrews County (both with a working interest of 100%).
Added
On March 31, 2025, in connection with the closing of the Lime Rock Acquisition, the Company and Lime Rock entered into a customary registration rights agreement relating to the LRR Shares. On May 2, 2025, a registration statement on Form S-3 with respect to the resale of the LRR Shares was declared effective by the SEC.
Removed
Market Conditions and Commodity Prices Our financial results depend on many factors, particularly the price of crude oil and natural gas and our ability to market our production on economically attractive terms.
Added
Credit Agreement On June 18, 2025, the Company as borrower, Bank of America, N.
Removed
Federal Reserve have resulted in increased interest rates on debt, contributed to debt and equity market volatility, and increased substantially our interest expense.
Added
All of the obligations under the Credit Agreement, and the guarantees of those obligations, are secured by substantially all of the Company’s assets.
Removed
Oil sales increased approximately $14.9 million to $364.0 million in 2024 from $349.0 million in 2023.
Added
Among other things, the Credit Agreement changed the administrative agent from Truist Bank to Bank of America; reduced the borrowing base and aggregate elected commitment from $600 million to $585 million; extended the maturity date of the Credit Agreement from August 31, 2026 to June 18, 2029; reduced the applicable margin pricing grid by 25 basis points; and made certain administrative changes to the Existing Credit Agreement.
Removed
The oil sales increased by a volume variance of approximately $103.9 million from a significant increase in sales volumes to 4,579,942 barrels of oil in 2023 from 3,459,840 barrels of oil in 2022, with approximately 19% of the increase in oil volumes related to the Founders Acquisition.

… 59 more changes not shown on this page.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

9 edited+2 added−1 removed5 unchanged
Biggest changeWe believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas. 61 Table of Contents For the Year Ended As of December 31, 2024 December 31, 2024 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues Percentage of accounts receivables from the sale of our oil and natural gas production Purchaser: Phillips 66 Company ("Phillips") 61% 64% Concord Energy LLC ("Concord") 14% 11% LPC Crude III, LLC ("LPC") 13% 11% Interest Rate Risk We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations.
Biggest changeFor the year ended As of December 31, 2025 December 31, 2025 Percentage of Oil, Natural Gas, and Natural Gas Liquids Revenues Percentage of accounts receivables from the sale of our oil and natural gas production Purchaser: Phillips 66 Company ("Phillips") 67% 66% Concord Energy LLC ("Concord") 13% 10% NGL Crude Partners ("NGL Crude") 9% 6% Interest Rate Risk We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility, which bears variable interest based upon a prime rate and is therefore susceptible to interest rate fluctuations.
A 1% change in the interest rate on our Credit Facility would result in an estimated $3.9 million change in our annual interest expense. See "NOTE 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Company’s interest rates of our Credit Facility.
A 1% change in the interest rate on our Credit Facility would result in an estimated $4.2 million change in our annual interest expense. See "NOTE 9 — REVOLVING LINE OF CREDIT" in the notes to the financial statements for more information on the Company’s interest rates of our Credit Facility.
Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility. As of December 31, 2024, we had $385 million outstanding on our Credit Facility with a weighted average annual interest rate for the year then ended of 9.2%.
Changes in interest rates affect the interest earned on the Company’s cash and cash equivalents and the interest rate paid on borrowings under the Credit Facility. As of December 31, 2025, we had $420 million outstanding on our Credit Facility with a weighted average annual interest rate for the year then ended of 8.2%.
In some months, fees exceeded the pricing, causing a negative net realized price. Gross natural gas prices ranged from a monthly average low of $(0.82) per Mcf to a monthly average high of $2.43 per Mcf. Fees ranged from a monthly average low of $(1.88) per Mcf to a monthly average high of $(1.44) per Mcf.
In some months, fees exceeded the pricing, causing a negative net realized price. Gross natural gas prices ranged from a monthly average low of $(1.46) per Mcf to a monthly average high of $2.89 per Mcf. Fees ranged from a monthly average low of $(2.35) per Mcf to a monthly average high of $(1.88) per Mcf.
NGL prices received during 2024 ranged from a monthly average low of $7.04 per barrel to a monthly average high of $12.43 per barrel. A significant decline in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations.
NGL prices received during 2025 ranged from a monthly average low of $4.33 per barrel to a monthly average high of $11.34 per barrel. A significant decline in the prices of oil or natural gas would likely have a material adverse effect on our financial condition and results of operations.
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None.
Item 9: Changes in and Disagreements with Accountants on Accounting and Financial Disclosure None. 65 Table of Contents
In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. The following table summarizes the Company's hedges in place on a monthly basis by commodity type.
In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production.
The following table sets forth certain information regarding the top three purchasers of our oil, natural gas, and NGLs for the year ended December 31, 2024.
The following table sets forth certain information regarding the top three purchasers of our oil, natural gas, and NGLs for the year ended December 31, 2025. We believe that the loss of any of these purchasers would not materially impact our business because we could readily find other purchasers for our oil and natural gas.
Oil prices received during 2024 ranged from a monthly average low of $67.84 per barrel to a monthly average high of $84.43 per barrel. Natural gas prices realized during 2024 ranged from a monthly average low of $(2.38) per Mcf to a monthly average high of $0.91 per Mcf.
Oil prices received during 2025 ranged from a monthly average low of $55.46 per barrel to a monthly average high of $73.75 per barrel. Natural gas prices realized during 2025 ranged from a monthly average low of $(3.51) per Mcf to a monthly average high of $1.01 per Mcf.
Removed
See "NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS" to our financial statements for further information. 60 Table of Contents Oil Hedges (WTI) Gas Hedges (Henry Hub) Month Average BBL/day Average MMBtu/day January 2025 7,420 — February 2025 10,939 8,557 March 2025 9,963 7,558 April 2025 10,008 7,643 May 2025 9,616 7,248 June 2025 9,684 7,350 July 2025 9,333 6,987 August 2025 9,203 6,863 September 2025 9,290 6,970 October 2025 8,977 6,632 November 2025 9,071 6,743 December 2025 8,779 6,500 January 2026 5,211 6,327 February 2026 5,681 6,904 March 2026 5,056 6,150 April 2026 5,150 6,257 May 2026 4,914 5,971 June 2026 5,010 6,083 July 2026 4,781 5,809 August 2026 4,721 5,732 September 2026 4,817 5,846 October 2026 4,603 5,584 November 2026 4,700 5,703 December 2026 4,494 5,455 Customer Credit Risk Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $33.8 million as of December 31, 2024).
Added
The following table summarizes the Company's hedges in place on a monthly basis by commodity type, for the next two years. See "NOTE 7 — DERIVATIVE FINANCIAL INSTRUMENTS" to our financial statements for further information.
Added
Oil Hedges (WTI) Gas Hedges (Henry Hub) Month Average BBL/day Average MMBtu/day January 2026 6,663 — February 2026 7,252 16,313 March 2026 6,411 14,482 April 2026 6,517 14,721 May 2026 6,204 14,024 June 2026 6,310 14,275 July 2026 6,007 13,614 August 2026 5,914 13,425 September 2026 6,051 13,685 October 2026 5,765 13,071 November 2026 5,867 13,335 December 2026 5,623 12,744 January 2027 5,548 25,176 February 2027 6,071 27,532 March 2027 5,403 24,580 April 2027 5,533 25,114 May 2027 5,290 24,011 June 2027 5,400 24,544 July 2027 4,710 23,472 August 2027 4,645 23,221 September 2027 4,733 23,744 October 2027 4,489 22,736 November 2027 4,590 23,247 December 2027 4,391 22,260 64 Table of Contents Customer Credit Risk Our principal exposure to credit risk is through receivables from the sale of our oil and natural gas production (approximately $29.6 million as of December 31, 2025).

Other REI 10-K year-over-year comparisons