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What changed in DORCHESTER MINERALS, L.P.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of DORCHESTER MINERALS, L.P.'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.

+179 added−184 removedSource: 10-K (2026-02-24) vs 10-K (2025-02-20)

Top changes in DORCHESTER MINERALS, L.P.'s 2025 10-K

179 paragraphs added · 184 removed · 145 edited across 6 sections

Item 1. Business

Business — how the company describes what it does

10 edited+0 added−3 removed51 unchanged
Biggest changeWe expect to benefit from continued operator development and believe the new production will help offset other mature property production declines. ● Seek to acquire from time to time, accretive mineral or other interests in producing oil and natural gas properties that meet our acquisition criteria.
Biggest changeProduction from our mineral interests could increase as operators continue to drill, complete and develop our acreage. We expect to benefit from continued operator development and believe the new production will help offset other mature property production declines. ● Seek to acquire from time to time, accretive mineral or other interests in producing oil and natural gas properties.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired overriding royalty interests totaling approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired royalty interests totaling approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral, royalty, or net profits interests in producing or non-producing oil and natural gas properties. We prefer to issue equity as consideration in contribution and exchange transactions. ● Maintain a conservative capital structure.
Since our formation, we have acquired, and may have additional opportunities from time to time in the future to acquire, mineral, royalty, or net profits interests in producing or non-producing oil and natural gas properties. We prefer to issue equity as consideration in non-taxable contribution and exchange transactions. ● Maintain a conservative capital structure.
In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for these and other oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price.
In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for additional oil and natural gas properties. Further, oil and natural gas compete with other forms of energy available to customers, primarily based on price.
Human Capital Resources Employees As of February 20, 2025, the Operating Partnership had 27 full-time employees in our Dallas, Texas corporate office. Our workforce is our most important asset, and we structure compensation and benefit programs to attract and retain high quality colleagues while providing a flexible hybrid work environment.
Human Capital Resources Employees As of February 24, 2026, the Operating Partnership had 26 full-time employees in our Dallas, Texas corporate office. Our workforce is our most important asset, and we structure compensation and benefit programs to attract and retain high quality colleagues while providing a flexible hybrid work environment.
Our primary business objective is to provide an attractive yield to our unitholders by focusing on strategically managing our assets and protecting our balance sheet, while maintaining a best-in-class cost structure. We intend to accomplish this objective by executing the following strategies: ● Capitalize on the development of the properties underlying our mineral interests.
Our primary business objective is to provide an attractive yield to our unitholders by focusing on strategically managing our assets and protecting our balance sheet, while striving to minimize our cost structure. We intend to accomplish this objective by executing the following strategies: ● Capitalize on the development of the properties underlying our mineral interests.
We have established a website at www.dmlp.net that contains the last annual meeting presentation and a link to the NASDAQ website. You may obtain all current filings free of charge at our website.
We have established a website at www.dmlp.net that contains the last annual meeting presentation. You may obtain all current filings free of charge through our website.
Royalty revenues from properties operated by Exxon Mobil Corporation and Diamondback Energy, Inc., together, represented approximately 31% of total operating revenues for the year ended December 31, 2024. Competition The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources.
Royalty revenues from properties operated by Exxon Mobil Corporation and its subsidiaries and Chevron Corporation and its subsidiaries, together, represented approximately 25% of total operating revenues for the year ended December 31, 2025. Competition The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources.
Except in connection with qualifying acquisitions, we do not currently anticipate issuing additional partnership securities. We have an effective registration statement registering 10,000,000 common units that may be offered and issued by the Partnership from time to time in connection with asset acquisitions or other business combination transactions. At present, 7,340,018 units remain available under the Partnership’s registration statement.
Except in connection with qualifying acquisitions, we do not currently anticipate issuing additional partnership securities. We have effective registration statements registering 22,659,982 common units that may be offered and issued by the Partnership from time to time in connection with asset acquisitions or other business combination transactions. At present, 19,084,306 units remain available under the Partnership’s registration statements.
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
On August 29, 2025, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
Removed
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
Removed
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership issued pursuant to the Partnership’s registration statement on Form S-4.
Removed
Production from our mineral interests could increase as operators continue to drill, complete and develop our acreage.

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

61 edited+17 added−11 removed257 unchanged
Biggest changeWe will be subject to federal income tax and possibly certain state corporate income or franchise taxes if we are classified as a corporation and not as a partnership for federal income tax purposes. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes.
Biggest changeOur unitholders and General Partner will bear, directly or indirectly, the costs of any contest with the IRS or other taxing authority. We will be subject to federal income tax and possibly certain state corporate income or franchise taxes if we are classified as a corporation and not as a partnership for federal income tax purposes.
Our unitholders do not have the right to replace an operator. Our lease bonus revenue depends in significant part on the actions of third parties, which are outside of our control. Significant portions of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right to grant leases of these interests to third parties.
Our unitholders do not have the right to replace an operator. Our lease bonus revenue depends in significant part on the actions of third parties, which are outside of our control. Portions of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right to grant leases of these interests to third parties.
On April 10, 2024, the BLM published a final replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and natural gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring.
Notably, on April 10, 2024, the BLM published a final replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and natural gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring.
We compete with other companies and producers for acquisitions of oil and natural gas interests. Many of these competitors have substantially greater financial and other resources than we do. Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will not have the opportunity to evaluate.
We compete with other companies and producers for acquisitions of oil and natural gas interests. Many of these competitors have substantially greater financial flexibility and other resources than we do. Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will not have the opportunity to evaluate.
Public health threats and other highly communicable diseases, outbreaks of which have been occurring in across the world, including the United States, could adversely impact our Partnership, drilling activities on our properties and the global economy.
Public health threats and other highly communicable diseases, outbreaks of which have been occurring across the world, including the United States, could adversely impact our Partnership, drilling activities on our properties and the global economy.
In implemented, methane emissions charge could increase our operators’ costs, which could adversely impact our business, financial condition and cash flows. However, on January 20, 2025, President Trump signed multiple executive orders seeking to reverse these climate incentives, including pausing the disbursement of funds under the IRA.
If implemented, methane emissions charge could increase our operators’ costs, which could adversely impact our business, financial condition and cash flows. However, on January 20, 2025, President Trump signed multiple executive orders seeking to reverse these climate incentives, including pausing the disbursement of funds under the IRA.
The terms of the NPIs provide for excess costs that cannot be charged currently because they exceed current revenues to be accumulated and charged in future periods, which could result in us not receiving any payments under the NPIs until all prior uncharged costs have been recovered by the Operating Partnership.
The terms of the NPI provide for excess costs that cannot be charged currently because they exceed current revenues to be accumulated and charged in future periods, which could result in us not receiving any payments under the NPI until all prior uncharged costs have been recovered by the Operating Partnership.
For example, these unitholders would be able to influence amendments of our organizational documents, or approval of any merger, sale of assets, or other major corporate transaction. 13 Table of Contents Our General Partner and its affiliates have conflicts of interests, which may permit our General Partner and its affiliates to favor their own interests to the detriment of unitholders.
For example, these unitholders would be able to influence amendments of our organizational documents, or approval of any merger, sale of assets, or other major corporate transactions. 13 Table of Contents Our General Partner and its affiliates have conflicts of interests, which may permit our General Partner and its affiliates to favor their own interests to the detriment of unitholders.
In addition, under the terms of the NPIs, the costs of unsuccessful future drilling on the working interest properties that are subject to the NPIs will reduce amounts payable to us under the NPIs by 96.97% of these costs. Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition.
In addition, under the terms of the NPI, the costs of unsuccessful future drilling on the working interest properties that are subject to the NPI will reduce amounts payable to us under the NPI by 96.97% of these costs. Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition.
The Operating Partnership may transfer or abandon properties that are subject to the NPIs. Our General Partner, through the Operating Partnership, may at any time transfer all or part of the properties underlying the NPIs. Our unitholders are not entitled to vote on any transfer; however, any such transfer must also simultaneously include the NPIs at a corresponding price.
The Operating Partnership may transfer or abandon properties that are subject to the NPI. Our General Partner, through the Operating Partnership, may at any time transfer all or part of the properties underlying the NPI. Our unitholders are not entitled to vote on any transfer; however, any such transfer must also simultaneously include the NPI at a corresponding price.
Because of this geographic concentration, any regional events, including natural disasters that increase costs, reduce availability of equipment, services, or supplies, reduce demand or limit production may impact the net proceeds payable under the NPIs more than if the properties were more geographically diversified.
Because of this geographic concentration, any regional events, including natural disasters that increase costs, reduce availability of equipment, services, or supplies, reduce demand or limit production may impact the net proceeds payable under the NPI more than if the properties were more geographically diversified.
Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Royalty Properties and the operators of the working interests and other properties underlying our NPIs to dispose of produced water and ultimately increase the cost of operation of the Royalty Properties and the working interests and other properties underlying our NPIs or delay production schedules.
Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Royalty Properties and the operators of the working interests and other properties underlying our NPI to dispose of produced water and ultimately increase the cost of operation of the Royalty Properties and the working interests and other properties underlying our NPI or delay production schedules.
In addition, if we issued limited partnership units with voting rights superior to the common units, it could adversely affect our unitholders' voting power. Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of certain distributions.
In addition, if we issue limited partnership units with voting rights superior to the common units, it could adversely affect our unitholders' voting power. Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of certain distributions.
Any uninsured costs relating to the properties underlying the NPIs will be deducted as a production cost in calculating the net proceeds payable to us. Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions.
Any uninsured costs relating to the properties underlying the NPI will be deducted as a production cost in calculating the net proceeds payable to us. Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions.
The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders ’ allocable share of our net income, in which case our unitholders ’ tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.
The 20% deduction for certain pass-through income may not be available for our unitholders ’ allocable share of our net income, in which case our unitholders ’ tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.
Under the terms of the NPIs, virtually all costs that may be incurred in connection with the properties, including overhead costs that are not subject to an annual reimbursement limit, are deducted as production costs or excess production costs in determining amounts payable to us.
Under the terms of the NPI, virtually all costs that may be incurred in connection with the properties, including overhead costs that are not subject to an annual reimbursement limit, are deducted as production costs or excess production costs in determining amounts payable to us.
We may experience delays in received royalty payments and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
We may experience delays in receiving royalty payments and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.
Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition. The Operating Partnership may participate in drilling activities in limited circumstances on the properties underlying the NPIs, and third parties may undertake drilling activities on our properties.
Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition. The Operating Partnership may participate in drilling activities in limited circumstances on the properties underlying the NPI, and third parties may undertake drilling activities on our properties.
Therefore, to the extent of the revenues from the burdened properties, we bear 96.97% of the costs of the working interest properties. If costs exceed revenues, we do not receive any payments under the NPIs. However, except as described below, we are not required to pay any excess costs.
Therefore, to the extent of the revenues from the burdened properties, we bear 96.97% of the costs of the working interest properties. If costs exceed revenues, we do not receive any payments under the NPI. However, except as described below, we are not required to pay any excess costs.
Our unitholders are not able to influence or control the operation or future development of the properties underlying the NPIs. The Operating Partnership is unable to influence the operations or future development of properties that it does not operate. The current operators of the properties underlying the NPIs are under no obligation to continue operating the underlying properties.
Our unitholders are not able to influence or control the operation or future development of the properties underlying the NPI. The Operating Partnership is unable to influence the operations or future development of properties that it does not operate. The current operators of the properties underlying the NPI are under no obligation to continue operating the underlying properties.
The Operating Partnership or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the NPIs relating to the abandoned well or property.
The Operating Partnership or any transferee may abandon any well or property if it reasonably believes that the well or property can no longer produce in commercially economic quantities. This could result in termination of the NPI relating to the abandoned well or property.
Cash distributions are affected by production and other costs, most of which are outside of our control. The cash available for distribution that comes from our royalty and mineral interests, including the NPIs, is directly affected by increases in production costs and other costs.
Cash distributions are affected by production and other costs, most of which are outside of our control. The cash available for distribution that comes from our royalty and mineral interests, including the NPI, is directly affected by increases in production costs and other costs.
A significant portion of the properties subject to the NPIs are geographically concentrated, which could cause net proceeds payable under the NPIs to be impacted by regional events. A significant portion of the properties subject to the NPIs are properties located in the Bakken region and Permian Basin.
A significant portion of the properties subject to the NPI are geographically concentrated, which could cause net proceeds payable under the NPI to be impacted by regional events. A significant portion of the properties subject to the NPI are properties located in the Bakken region and Permian Basin.
Oil and natural gas markets remain subject to price volatility, which may have a material adverse effect on our cash distributions in periods of lower prices. During periods of substantial declines in prices, such as in 2020, oil and natural gas operators on our properties may suspend drilling programs, which would impact our revenues and operating income.
Oil and natural gas markets remain subject to price volatility, which may have a material adverse effect on our cash distributions in periods of lower prices. During periods of substantial declines in prices, oil and natural gas operators on our properties may suspend drilling programs, which would impact our revenues and operating income.
A unitholder may lose his status as a partner of our Partnership for federal income tax purposes if the unitholder lends our common units to a short seller to cover a short sale of such common units.
A unitholder may lose its status as a partner of our Partnership for federal income tax purposes if the unitholder lends our common units to a short seller to cover a short sale of such common units.
If a unitholder loans his common units to a short seller to cover a short sale of common units, the unitholder may be considered as having disposed of his ownership of those common units for federal income tax purposes.
If a unitholder loans its common units to a short seller to cover a short sale of common units, the unitholder may be considered as having disposed of its ownership of those common units for federal income tax purposes.
Before you invest, you should be aware that the occurrence of any of the events herein described in "Item 1A – Risk Factors" and elsewhere in this report and in the Partnership’s other filings with the Securities and Exchange Commission could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment. 18 Table of Contents ITEM 1B.
Before you invest, you should be aware that the occurrence of any of the events herein described in “Item 1A – Risk Factors” and elsewhere in this report and in the Partnership’s other filings with the Securities and Exchange Commission could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment. 18 Table of Contents
Furthermore, the oil and natural gas industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties.
Furthermore, the oil and natural gas industry has and continues to experience consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources. Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
If the IRS makes audit adjustments to our income tax returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced.
We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under "Risk Factors" and elsewhere in this report.
We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under “Risk Factors” and elsewhere in this report.
Moreover, due to the extremely volatile market conditions, we are unable to predict the degree or duration of any adverse impact on our operations and financial condition and other risks in our industry may be enhanced by such conditions. 8 Table of Contents Continuing or worsening inflationary issues and associated changes in federal monetary policy may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise and may delay or restrict their exploration and development activities.
Moreover, due to the extremely volatile market conditions, we are unable to predict the degree or duration of any adverse impact on our operations and financial condition and other risks in our industry may be enhanced by such conditions. 8 Table of Contents Continuing or worsening domestic inflationary issues and associated changes in federal monetary policy and increased tariffs by the United States on foreign jurisdictions may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise and may delay or restrict their exploration and development activities and in turn our business.
Under the terms of the NPIs, much of the economic risk of the underlying properties is passed along to us.
Under the terms of the NPI, much of the economic risk of the underlying properties is passed along to us.
West Texas Minerals LLC and Carrollton Mineral Partners, LP, and certain affiliates, beneficially hold, in the aggregate, approximately 6.9% of our outstanding Units.
West Texas Minerals LLC and Carrollton Mineral Partners, LP, and certain affiliates, beneficially hold, in the aggregate, approximately 5.2% of our outstanding Units.
The Partnership may be adversely affected by price volatility in the oil and natural gas markets. Historically, there has been price volatility in the oil and natural gas markets, which have been impacted by a number of factors, including actions by oil producing nations.
Historically, there has been price volatility in the oil and natural gas markets, which have been impacted by a number of factors, including actions by oil producing nations.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017, it may collect any resulting taxes (including any applicable penalties and interest) directly from us.
If the IRS makes audit adjustments to our income tax returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us.
These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require our operators to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.
These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require our operators to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions, and compliance timeframes may be adjusted through EPA rulemakings or state plan approvals.
While this litigation does not directly impact our operations, we derive a significant amount of revenue from the Royalty Properties and NPIs we hold in the Bakken region, the region for which the Dakota Access Pipeline is intended to be a key pipeline.
Accordingly, the continued operation of Dakota Access Pipeline in the future is uncertain. While this litigation does not directly impact our operations, we derive a significant amount of revenue from the Royalty Properties and NPI we hold in the Bakken region, the region for which the Dakota Access Pipeline is considered to be a key pipeline.
Because these shared officers function as both our representatives and those of our General Partner and its affiliates and of third parties, conflicts of interest could arise between our General Partner and its affiliates, on the one hand, and us or our unitholders, on the other, or between us or our unitholders on the one hand and the third parties for which our officers also serve management functions.
Because these shared officers function as both our representatives and those of our General Partner and its affiliates, conflicts of interest could arise between our General Partner and its affiliates, on the one hand, and us or our unitholders, on the other.
Cyber incidents or attacks targeting our systems and infrastructure used by the oil and natural gas industry may adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our business may be adversely impacted.
Cyber incidents or attacks targeting our systems and infrastructure used by the oil and natural gas industry and the use of artificial intelligence tools by us, the operators of our properties, vendors, suppliers, and other business partners may adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our business may be adversely impacted.
Thereafter, in 2021, oil and natural gas prices significantly rebounded. However, global military conflicts, fluctuating interest rates, changes in tariff rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation, and actions taken by OPEC and its non-OPEC allies, collectively OPEC+, continued to contribute to economic and pricing volatility during 2024.
Global military conflicts and political uncertainty, fluctuating interest rates, changes in tariff rates, global supply chain disruptions, concerns about a potential economic downturn or recession, recent measures to combat persistent inflation, and actions taken by OPEC and its non-OPEC allies, collectively OPEC+, continued to contribute to economic and pricing volatility during 2025.
We do not control operations and development of the Royalty Properties or the properties underlying the NPIs that the Operating Partnership does not operate, which could impact the amount of our cash distributions.
We do not control operations and development of the Royalty Properties or the properties underlying the NPI, which could impact the amount of our cash distributions.
Recently, the U.S. has had periods of high inflation. These inflationary pressures may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise. Sustained levels of high inflation have likewise caused the U.S.
Recently, the U.S. has had periods of high inflation and increased tariffs on foreign jurisdictions. These inflationary and tariff pressures have resulted, and may continue to result, in increases to the costs of the goods, services and labor used by our operators, which has and may continue to cause their capital expenditures and operating costs to rise.
The loss of the services of any of these key personnel could have a material adverse effect on the results of our operations. We have not obtained insurance or entered into employment agreements with any of these key personnel. We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.
We have not obtained insurance or entered into employment agreements with either of these key personnel. We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.
Though President Trump issued an executive order on January 20, 2025, directing the United States Ambassador to the United Nations to immediately withdraw from the Paris Agreement, it is possible that the Paris Agreement and other domestic and international regulatory requirements will have an adverse effect on the demand for oil and natural gas products. 11 Table of Contents Although it is not possible at this time to predict whether or when Congress may adopt additional climate change legislation, or whether EPA may promulgate additional regulation of GHGs from the oil and natural gas industry, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require oil and natural gas operators that develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas produced from our properties.
It is possible that the withdrawals will impact the demand for oil and natural gas products. 11 Table of Contents Although it is not possible at this time to predict whether or when Congress may adopt additional climate change legislation, or whether EPA may promulgate additional regulation of GHGs from the oil and natural gas industry, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require oil and natural gas operators that develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas produced from our properties.
As a public company, we have incurred and will continue to incur significant legal, accounting and other expenses, particularly since we are now a large accelerated filer and are no longer a smaller reporting company.
As a public company and large accelerated filer, we have incurred and will continue to incur significant legal, accounting and other expenses.
In addition, certain cyber incidents, such as surveillance, may remain undetected for some period of time. While we utilize various procedures and controls to mitigate exposure to such risk, cyber incidents and attacks are evolving and unpredictable. Our information technology systems and any insurance coverage for protecting against cybersecurity risks may not be sufficient.
In addition, certain cyber incidents, such as surveillance, may remain undetected for some period of time. While we utilize various procedures and controls to mitigate exposure to such risk, cyber incidents and attacks are evolving and unpredictable.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a publicly traded partnership’s U.S. trade or business.
Under current law, which made permanent the 20% deduction that was set to expire on December 31, 2025, an individual taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a publicly traded partnership’s U.S. trade or business.
It is impossible to predict the effect of the continued spread, or fear of continued spread, of COVID-19 and its ongoing variants globally.
It is impossible to predict the effect of a global public health crisis, including continued spread, or fear of continued spread, of COVID-19 and its ongoing variants globally or the occurrence of a new global public health crisis of similar magnitude.
We cannot predict the final regulatory requirements or the cost to our operators to comply with such requirements with any certainty. 9 Table of Contents The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands.
The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands.
These statements can be identified by the use of forward-looking terminology including "may," "believe," "will," "expect," "anticipate," "estimate," "continue," or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other forward-looking information.
These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “will,” “expect,” “anticipate,” “estimate,” “continue,” or other similar words. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other forward-looking information.
Such federal legislation or regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing. In addition, on March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands.
Such federal legislation or regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing. The Bureau of Land Management (“BLM”) is responsible for protecting the resources and managing the uses of America’s public lands.
Federal changes will affect state air permitting programs in states that administer the federal CAA under a delegation of authority, including states in which we have operations.
Federal changes will affect state air permitting programs in states that administer the federal CAA under a delegation of authority, including states in which we have operations, and states will be required to adopt implementing plans for existing sources consistent with EPA’s emissions guidelines.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a "qualifying income" requirement.
No assurance can be given that public health threats will not have a material adverse effect, and that any further spread of COVID-19 and its ongoing variants will not have a material adverse effect, on our business, operations and financial results. The Partnership may be adversely affected by the international economic instability caused by ongoing global conflicts.
No assurance can be given that public health threats will not have a material adverse effect on our business, operations and financial results. The Partnership may be adversely affected by the international economic instability caused by ongoing global conflicts. From 2022 through 2025, multiple global military conflicts arose causing instability in the international economy which has continued into 2026.
Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, public health crises including the worldwide coronavirus (COVID-19) outbreak beginning in early 2020 and its ongoing variants, the conflict in Ukraine, the conflict between Israel and Hamas, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations.
Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, public health crises, the conflicts in Ukraine and the Middle East, the political uncertainty in Venezuela, changes in the operations on or development of our properties, changes in economic and industry conditions (including changes to tariff and import/export regulations by the United States or other countries) and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations.
However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us. A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
A change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our General Partner, particularly William Casey McManemin, its Chief Executive Officer, and our Chief Executive Officer, Bradley J. Ehrman, and Chief Financial Officer, Leslie A. Moriyama.
Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our General Partner, our Chief Executive Officer, Bradley J. Ehrman, and Chief Financial Officer, Leslie A. Moriyama. The loss of the services of either of these key personnel could have a material adverse effect on the results of our operations.
At its height, the COVID-19 pandemic had a significant negative effect on the global economy, supply chains and labor force participation, and created significant volatility in financial markets. Although the effects of the pandemic during 2022 were not as significant as prior years, new variants continued to cause waves of COVID-19 cases around the world.
At its height, the COVID-19 pandemic had a significant negative effect on the global economy, supply chains and labor force participation, and created significant volatility in financial markets.
The COVID-19 pandemic and its ongoing variants may continue to have a material adverse effect on the demand for hydrocarbons and the prices at which they are sold, which may impact our revenues and operating income, our cash distributions and our business generally.
While in May 2023 the World Health Organization (“WHO”) determined COVID-19 to be an established and ongoing health issue which no longer constitutes a public health emergency of international concern, the COVID-19 pandemic and its ongoing variants or a new global public health crisis may have a material adverse effect on the demand for hydrocarbons and the prices at which they are sold, which may impact our revenues and operating income, our cash distributions and our business generally.
As cyber security threats continue to evolve, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. It is possible that our business, finances, systems and assets could be compromised in a cyber attack.
As cyber security threats continue to evolve, including those leveraging the increasing availability and sophistication of artificial intelligence tools, we may be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber incidents. We may not have sufficient resources available to do so on a timely basis.
Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our operators’ businesses.
Sustained levels of high interest rates, combined with expectations of no further rate cuts and potential future rate increases, as well as potential volatility in monetary policy resulting from new leadership at the federal reserve, could raise the cost of capital and depress economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our operators’ businesses.
Removed
For example, after OPEC and a group of oil producing nations led by Russia failed in March 2020 to agree on oil production cuts, Saudi Arabia announced that it would cut oil prices and increase production, leading to a sharp decline in oil and natural gas prices.
Added
Security vulnerabilities may be introduced from the use of artificial intelligence by us, the operators of our properties, vendors, suppliers, and other business partners. Our information technology systems and any insurance coverage for protecting against cybersecurity risks may not be sufficient.
Removed
While OPEC, Russia and other oil producing countries reached an agreement in April 2020 to reduce production levels, and U.S. production declined, oil prices remained lower than in previous years on account of an oversupply of oil and natural gas, with a simultaneous decrease in demand as a result of the impact of COVID-19 on the global economy.
Added
It is not possible to predict all of the risks related to the use of artificial intelligence. It is possible that our business, finances, systems and assets could be compromised in a cyber attack or from the unintended consequences of the use of artificial intelligence tools by us, the operators of our properties, vendors, suppliers, and other business partners.
Removed
The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water.
Added
In addition, new laws and regulations regarding cybersecurity and artificial intelligence may pose increasingly complex compliance challenges and potentially elevate costs, and any failure to comply with these laws and regulations could result in significant penalties and legal liability. The Partnership may be adversely affected by price volatility in the oil and natural gas markets.
Removed
Also, on November 18, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands. On March 28, 2017, President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them.
Added
Sustained levels of high inflation have likewise caused the U.S. Federal Reserve and other central banks to increase interest rates through 2025, with only slight moderation later in the year.
Removed
Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. A coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission.
Added
Separately, on July 4, 2025, President Trump signed the One Big Beautiful Bill Act, which amended CAA section 136(g) to delay the collection of data regarding the annual GHG emissions for oil and natural gas systems to 2034 and for each year thereafter, which may affect overall compliance timeframe.
Removed
Also, on September 28, 2018, the BLM published a final rule to revise the 2016 methane rule; however, a federal court struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck down the 2016 methane rule.
Added
We cannot predict the final regulatory requirements or the cost to our operators to comply with such requirements with any certainty. 9 Table of Contents On February 12, 2026, EPA announced a final rule rescinding its 2009 GHG Endangerment Finding (a regulatory determination that GHGs, specifically carbon dioxide, methane, nitrous oxide, hydrofluorocarbons, perfluorocarbons, and sulfur hexafluoride, threaten public health and welfare), and repealing all GHG emission standards and associated compliance, testing, reporting, averaging, banking and trading provisions for light-, medium-, and heavy-duty motor vehicles and engines under section 202(a) of the CAA.
Removed
At the international level, the United States has been involved in negotiations regarding GHG reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”). The U.S. was among approximately 195 nations that signed an international accord in December 2015, the so called Paris Agreement, which became effective on November 4, 2016, with the objective of limiting GHG emissions.
Added
Although EPA deferred action on regulatory rollbacks of other GHG standards and reporting requirements under the CAA, revocation of the 2009 GHG Endangerment Finding marks a major shift in federal regulation and could potentially impact obligations regarding other GHG emissions, including those from the oil and gas industry.
Removed
The USACOE and Dakota Access Pipeline filed motions to dismiss the case on January 17, 2025, though the matter remains pending. Accordingly, the continued operation of Dakota Access Pipeline in the future is uncertain.
Added
It is also possible that rescission of the 2009 GHG Endangerment Finding will give rise to greater and fragmented regulation at the state level, litigation from interested stakeholders challenging the repeal, and actions against GHG emitters under common law theories.
Removed
Some of our officers are also involved in management and ownership roles in other oil and natural gas enterprises and have similar duties to them and devote time to their businesses.
Added
Although we cannot predict whether and how federal and state regulators will proceed in the future, changes stemming from repeal of the EPA 2009 GHG Endangerment Finding could impact our operations and compliance costs.
Removed
Our unitholders and General Partner will bear, directly or indirectly, the costs of any contest with the IRS or other taxing authority. In 2020, we obtained a ruling from the IRS permitting us to aggregate the Minerals NPI, including the previously aggregated Maecenas NPI, Bradley NPI, Republic NPI, and Spinnaker NPI for federal income tax purposes effective January 1, 2020.

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Item 2. Properties

Properties — owned and leased real estate

26 edited+4 added−0 removed14 unchanged
Biggest changeSummary of Oil and Natural Gas Reserves as of Fiscal Year-End All Proved Developed Producing and located in the United States Royalty Properties Net Profits Interests(1) Total Year Oil(2) Natural Gas Oil(2) Natural Gas Oil(2) Natural Gas (mbbls) (mmcf) (mbbls) (mmcf) (mbbls) (mmcf) 2024 9,398 31,651 1,671 3,948 11,069 35,599 2023 6,642 28,138 1,676 5,213 8,318 33,351 2022 7,251 31,946 1,669 7,207 8,920 39,153 (1) Reserves reflect 96.97% of the corresponding amounts assigned to the Operating Partnership’s interests in the NPI properties.
Biggest changeOur internal controls over the reserves estimation process include verification of input data used in LPC’s reserves evaluation software as well as reviews by our petroleum engineer and CEO, which include the following: ● Review of ownership interests in the reserves database against our internal ownership data; ● Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database; ● Review of actual historical production volumes compared to projections in the reserve report; and ● Review of preliminary reserve estimates by our CEO with our petroleum engineer Summary of Oil and Natural Gas Reserves as of Fiscal Year-End All Proved Developed Producing and located in the United States Royalty Properties Net Profits Interests(1) Total Year Oil(2) Natural Gas Oil(2) Natural Gas Oil(2) Natural Gas (mbbls) (mmcf) (mbbls) (mmcf) (mbbls) (mmcf) 2025 8,174 31,239 1,298 5,393 9,472 36,632 2024 9,398 31,651 1,671 3,948 11,069 35,599 2023 6,642 28,138 1,676 5,213 8,318 33,351 (1) Reserves reflect 96.97% of the corresponding amounts assigned to the Operating Partnership’s interests in the NPI properties.
Consequently, the exact number of wells producing from or drilling on the Royalty Properties at a given point in time is not easily determinable. The primary manner by which we will become aware of activity on the Royalty Properties is the receipt of division orders or other correspondence from operators or purchasers.
Consequently, the exact number of wells producing from or drilling on the Royalty Properties at a given point in time is not easily determinable. The primary manner by which we will become aware of activity on the Royalty Properties is receipt of division orders or other correspondence from operators or purchasers.
In the event costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for properties subject to the NPI, no payment is made, and any deficit is accumulated and reflected in the following month's calculation of net profit.
In the event that costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for properties subject to the NPI, no payment is made, and any deficit is accumulated and reflected in the following month's calculation of net profit.
Title to Properties We believe we have satisfactory title to all of our assets. Record title to essentially all of our assets has undergone the appropriate filings in the jurisdictions in which such assets are located. Title to property may be subject to encumbrances.
Title to Properties We believe that we have satisfactory title to all of our assets. Record title to essentially all of our assets has undergone the appropriate filings in the jurisdictions in which such assets are located. Title to property may be subject to encumbrances.
Large, multi-well units paid on an aggregate basis are included as one gross well. 21 Table of Contents New Well Activity The following table sets forth first payments received for new wells on our Royalty Properties and NPI properties during 2024. The majority of the activity was concentrated in the Permian Basin, Bakken region, South Texas, and the Rockies.
Large, multi-well units paid on an aggregate basis are included as one gross well. 21 Table of Contents New Well Activity The following table sets forth first payments received for new wells on our Royalty Properties and NPI properties during 2025. The majority of the activity was concentrated in the Permian Basin, the Rockies, the Bakken region, and South Texas.
Productive Well Summary The following table sets forth, as of December 31, 2024, the approximate combined number of producing wells on the properties subject to the NPI. Gross wells refer to wells in which a working interest is owned. Net wells are determined by multiplying gross wells by our working interest in those wells.
Productive Well Summary The following table sets forth, as of December 31, 2025, the approximate combined number of producing wells on the properties subject to the NPI. Gross wells refer to wells in which a working interest is owned. Net wells are determined by multiplying gross wells by our working interest in those wells.
Acreage Summary The following table sets forth, as of December 31, 2024, a summary of our gross and net acres, where applicable, of mineral, royalty, overriding royalty and leasehold interests, and a compilation of the number of counties and parishes and states in which these interests are located. The majority of our net mineral acres are unleased.
Acreage Summary The following table sets forth, as of December 31, 2025, a summary of our gross and net acres, where applicable, of mineral, royalty, overriding royalty and leasehold interests, and a compilation of the number of counties and parishes and states in which these interests are located. The majority of our net mineral acres are unleased.
Acreage Summary The following tables set forth, as of December 31, 2024, information concerning properties owned by the Operating Partnership and subject to the NPI. Acreage amounts listed under “Leasehold” reflect gross acres leased by the Operating Partnership and the working interest share (net acres) in those properties.
Acreage Summary The following tables set forth, as of December 31, 2025, information concerning properties owned by the Operating Partnership and subject to the NPI. Acreage amounts listed under “Leasehold” reflect gross acres leased by the Operating Partnership and the working interest share (net acres) in those properties.
The following table sets forth, as of December 31, 2024, the combined summary of total gross and net acres, where applicable, of mineral, royalty, overriding royalty and leasehold interests in each of the states in which these interests are located. Overriding royalty interests are only included in gross acre totals.
The following table sets forth, as of December 31, 2025, the combined summary of total gross and net acres, where applicable, of mineral, royalty, overriding royalty and leasehold interests in each of the states in which these interests are located. Overriding royalty interests are only included in gross acre totals.
ITEM 2. PROPERTIES Facilities Our corporate office is located in Dallas, Texas and consists of 11,847 square feet of leased office space. Properties We own two categories of properties: Royalty Properties and net profits overriding royalty interests (referred to as the Net Profits Interest, or “NPI”).
ITEM 2. PROPERTIES Facilities Our corporate office is located in Dallas, Texas and consists of 11,847 square feet of leased office space. Properties We own two categories of properties: Royalty Properties and net profits overriding royalty interests (referred to as the “Net Profits Interest”, or “NPI”).
Overriding Mineral Royalty Royalty Leasehold Number of States 28 17 17 8 Number of Counties/Parishes 525 196 151 33 Gross Acres 2,951,000 679,000 370,000 24,000 Net Acres (where applicable) 471,000 - - - Our net interest in production from royalty, overriding royalty and leasehold interests is based on lease royalty and other third party contractual terms, which vary from property to property.
Overriding Mineral Royalty Royalty Leasehold Number of States 28 17 17 8 Number of Counties/Parishes 525 196 151 33 Gross Acres 2,953,000 679,000 370,000 24,000 Net Acres (where applicable) 473,000 - - - Our net interest in production from royalty, overriding royalty and leasehold interests is based on lease royalty and other third party contractual terms, which vary from property to property.
Ensuring compliance with generally accepted petroleum engineering and evaluation methods and procedures is the responsibility of the Partnership's Chief Executive Officer (“CEO”). Our CEO has a bachelor’s degree in Petroleum Engineering from the University of Alberta and has worked in the upstream oil and natural gas business in various capacities since 1996.
Ensuring compliance with generally accepted petroleum engineering and evaluation methods and procedures is the responsibility of the Partnership’s CEO. Our CEO has a bachelor’s degree in Petroleum Engineering from the University of Alberta and has worked in the upstream oil and natural gas business in various capacities since 1996.
These leases reflected bonus payments ranging up to $5,000/acre and initial royalty terms ranging up to 25%.
These leases reflected bonus payments ranging up to $15,000/acre and initial royalty terms ranging up to 25%.
State Gross Net State Gross Net Alabama 105,000 8,000 Montana 366,000 81,000 Arkansas 49,000 16,000 Nebraska 3,000 Colorado 73,000 5,000 New Mexico 58,000 3,000 Florida 89,000 25,000 New York 23,000 19,000 Georgia 4,000 1,000 North Dakota 523,000 82,000 Idaho 17,000 2,000 Ohio Illinois 5,000 1,000 Oklahoma 273,000 19,000 Indiana Oregon 6,000 1,000 Kansas 14,000 2,000 Pennsylvania 10,000 6,000 Kentucky 2,000 1,000 South Dakota 55,000 11,000 Louisiana 136,000 3,000 Texas 2,041,000 171,000 Michigan 54,000 3,000 Utah 6,000 Mississippi 81,000 9,000 West Virginia Missouri Wyoming 32,000 2,000 20 Table of Contents Leasing Activity We received $0.3 million during 2024 attributable to lease bonus on 19 leases or extension of existing leases in lands located in nine counties in four states.
State Gross Net State Gross Net Alabama 105,000 8,000 Montana 366,000 81,000 Arkansas 49,000 16,000 Nebraska 3,000 Colorado 75,000 7,000 New Mexico 58,000 3,000 Florida 89,000 25,000 New York 23,000 19,000 Georgia 4,000 1,000 North Dakota 523,000 82,000 Idaho 17,000 2,000 Ohio Illinois 5,000 1,000 Oklahoma 273,000 19,000 Indiana Oregon 6,000 1,000 Kansas 14,000 2,000 Pennsylvania 10,000 6,000 Kentucky 2,000 1,000 South Dakota 55,000 11,000 Louisiana 136,000 3,000 Texas 2,041,000 171,000 Michigan 54,000 3,000 Utah 6,000 Mississippi 81,000 9,000 West Virginia Missouri Wyoming 32,000 2,000 20 Table of Contents Leasing Activity We received $4.0 million during 2025 attributable to lease bonuses from new leases, extensions of existing leases, and pooling elections.
The following table sets forth a summary of leases and pooling elections consummated during 2022, 2023 and 2024. 2024 2023 2022 Number 19 14 31 Number of States 4 3 4 Number of Counties 9 11 17 Average Royalty(1) 24.3 % 25.0 % 24.2 % Average Bonus, $/acre(1) $ 532 $ 18,385 $ 10,268 Total Lease Bonus (in millions) $ 0.3 $ 12.7 $ 8.7 (1) Based on net acreage weighted average.
The following table sets forth a summary of new leases, lease extensions, and pooling elections consummated during 2023, 2024 and 2025. 2025 2024 2023 Number 27 19 14 Number of States 5 4 3 Number of Counties 13 9 11 Average Royalty(1) 23.4 % 24.3 % 25.0 % Average Bonus, $/acre(1) $ 4,779 $ 532 $ 18,385 Total Lease Bonus (in millions)(2) $ 4.0 $ 0.3 $ 12.7 (1) Based on net acreage weighted average.
In the event the NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership. From a cash perspective, as of December 31, 2024, the Minerals NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, equaling cash on hand of $3.5 million.
In the event that the NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership. From a cash perspective, as of December 31, 2025, the Minerals NPI had outstanding capital commitments, primarily in the Bakken region, of $8.5 million.
We have and will continue to consider a range of transaction structures for our unleased mineral interests including leasing to third parties, working interest participation through the Operating Partnership, electing non-consent under State laws, or a combination thereof. Oil and Natural Gas Reserves The below table reflects the Partnership's proved developed producing reserves at December 31, 2024.
We have and will continue to consider a range of transaction structures for our unleased mineral interests including leasing to third parties, working interest participation through the Operating Partnership, electing non-consent under State laws, or a combination thereof.
We receive monthly payments from the NPI equaling 96.97% of the net profits realized by the Operating Partnership from these properties in the preceding month.
Net Profits Interests The NPI represents a net profits overriding royalty interest burdening various properties owned by the Operating Partnership. We receive monthly payments from the NPI equaling 96.97% of the net profits realized by the Operating Partnership from these properties in the preceding month.
Productive Wells/Units(1) Gross Net Texas 543 18 North Dakota 552 11 All others 284 9 Total 1,379 38 (1) Defined as all wells/units for which we received production revenue during the calendar year.
Productive Wells/Units(1) Gross Net Texas 593 19 North Dakota 583 11 All others 269 7 Total 1,445 37 (1) Defined as all wells/units for which we received production revenue during the calendar year.
The Partnership does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty interests.
Our petroleum engineer met with our third party engineers periodically during the reserve report process to discuss the assumptions and methods used in the proved reserve estimation process. The Partnership does not have information that would be available to a company with oil and natural gas operations because detailed information is not generally available to owners of royalty interests.
The Partnership’s petroleum engineer provides production and accounting information to our independent petroleum engineering consulting firm who extrapolates from such information estimates of the reserves attributable to the Royalty Properties and NPI based on their expertise in the oil and natural gas fields where the Royalty Properties and NPI are situated, as well as publicly available information.
The third party reserve engineers extrapolate from this information estimates of the proved reserves attributable to the Royalty Properties and NPI based on their expertise in the oil and natural gas fields where the Royalty Properties and NPI are situated, as well as publicly available information.
Royalty Net Profits Properties(1) Interest Gross Wells 1,943 146 Net Wells 12 2 Number of States 7 5 Number of Counties/Parishes 49 17 (1) 130 gross and less than one net well additions were attributable to acquisitions closed during 2023.
Royalty Net Profits Properties(1) Interest Gross Wells 761 108 Net Wells 5 1 Number of States 6 4 Number of Counties/Parishes 39 15 (1) 224 gross and 1.5 net well additions were attributable to acquisitions closed during 2024.
Payments received for shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments and settlement proceeds are reflected in our accompanying consolidated financial statements in other operating revenues. Net Profits Interests The NPI represents a net profits overriding royalty interest burdening various properties owned by the Operating Partnership.
(2) Lease Bonus excludes proceeds of $5.4 million from assignment of leasehold in 2025. Payments received for shut-in and delay rental payments, coal royalty, surface use agreements, litigation judgments and settlement proceeds are reflected in our accompanying consolidated financial statements in other operating revenues.
The reserves are based on the reports of independent petroleum engineering consulting firm LaRoche Petroleum Consultants, Ltd. (“LPC”), who is registered with the Engineering Board of the State of Texas and has been engaged in the business of oil and natural gas property evaluation since its formation in 1979.
(“LPC”), who is registered with the Engineering Board of the State of Texas and has been engaged in the business of oil and natural gas property evaluation since its formation in 1979. Other than our filings with the SEC, we have not filed the estimated proved reserves with, or included them in any reports to, any federal agency.
These well additions were in nine counties and parishes and three states. 1,110 gross and eight net well additions were attributable to acquisitions closed during 2024. These well additions were in 15 counties in three states. We anticipate receiving more first payments for new wells attributable to acquisitions closed during 2024 in the first half of 2025.
We anticipate receiving more first payments for new wells attributable to the acquisition closed during the third quarter of 2025 in the first half of 2026.
Other than our filings with the SEC, we have not filed the estimated proved reserves with, or included them in any reports to, any federal agency. Copies of the reports prepared by LPC are attached hereto as Exhibits 99.1 and 99.2.
Copies of the reports prepared by LPC are attached hereto as Exhibits 99.1 and 99.2. The Partnership’s petroleum engineer and CEO work closely with our third party reserve engineers to ensure integrity, accuracy, and timeliness of the data used to calculate our estimated proved developed producing reserves.
Added
These well additions were in 13 counties and three states. 26 gross and 1.4 net well additions were attributable to the acquisition closed during the third quarter of 2025. These well additions were in Adams County, Colorado.
Added
Oil and Natural Gas Reserves The below table reflects the Partnership's proved developed producing reserves as of December 31, 2025, 2024, and 2023. The reserves are based on the reports of independent petroleum engineering consulting firm LaRoche Petroleum Consultants, Ltd.
Added
We provide historical information to the third party reserve engineers for our properties such as ownership interest, oil and natural gas production, realized commodity pricing, and production and operating costs.
Added
Our proved reserve estimates were prepared in accordance with our internal control procedures. During the period covered by the reserve report, our petroleum engineer met with LPC to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

6 edited+2 added−0 removed1 unchanged
Biggest changeThe stock performance shown on the graph below is not necessarily indicative of future price performance. 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 Dorchester Minerals, L.P. $ 100.00 $ 62.90 $ 125.23 $ 215.16 $ 257.02 $ 300.03 Industry Group $ 100.00 $ 51.65 $ 93.09 $ 149.33 $ 150.12 $ 180.02 S&P 500 Index $ 100.00 $ 118.40 $ 152.39 $ 124.79 $ 157.59 $ 197.02 23 Table of Contents Issuer Purchases of Equity Securities (c) (d) Total Maximum Number of Number Units of Units that Purchased May as Yet Be (a) (b) Part of Purchased Total Average Publicly Under the Number of Price Announced Plans Units Paid Plans or Period Purchased per Unit or Programs Programs October 1, 2024 – October 31, 2024 - N/A - 100,259 (1) November 1, 2024 – November 30, 2024 - N/A - 100,259 (1) December 1, 2024 – December 31, 2024 33,454 (2) $ 32.82 33,454 66,805 (1) Total 33,454 $ 32.82 33,454 66,805 (1) (1) The number of common units that our General Partner may grant under the Dorchester Minerals Management LP Equity Incentive Program, as amended and restated as of October 4, 2023, which was approved by our common unitholders on October 4, 2023 (the “Equity Incentive Program”), each fiscal year may not exceed 0.333% of the number of common units outstanding at the beginning of the fiscal year.
Biggest changeThe stock performance shown on the graph below is not necessarily indicative of future price performance. 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 12/31/2025 Dorchester Minerals, L.P. $ 100.00 $ 199.09 $ 342.06 $ 408.60 $ 476.98 $ 354.05 S&P 500 Index $ 100.00 $ 128.71 $ 105.40 $ 133.10 $ 166.04 $ 196.16 XOP $ 100.00 $ 163.88 $ 232.27 $ 234.03 $ 226.27 $ 215.83 Industry Peer Group $ 100.00 $ 183.47 $ 304.65 $ 318.66 $ 445.10 $ 406.36 23 Table of Contents Issuer Purchases of Equity Securities (c) (d) Total Maximum Number of Number Units of Units that Purchased May as Yet Be (a) (b) Part of Purchased Total Average Publicly Under the Number of Price Announced Plans Units Paid Plans or Period Purchased per Unit or Programs Programs October 1, 2025 – October 31, 2025 - N/A - 133,306 (1) November 1, 2025 – November 30, 2025 - N/A - 133,306 (1) December 1, 2025 – December 31, 2025 35,000 (2) $ 22.27 35,000 98,306 (1) Total 35,000 $ 22.27 35,000 98,306 (1) (1) The number of common units that our General Partner may grant under the Dorchester Minerals Management LP Equity Incentive Program, originally adopted on May 20, 2015, by Dorchester Minerals Operating LP, the Partnership’s sole limited partner, as amended and restated and adopted by the Partnership on October 20, 2022, and, subsequently, as amended and restated as of October 4, 2023, which was approved by our common unitholders on October 4, 2023 (the “Equity Incentive Program”), each fiscal year may not exceed 0.333% of the number of common units outstanding at the beginning of the fiscal year.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units trade on the NASDAQ Global Select Market under the ticker symbol “DMLP”. As of December 31, 2024, there were 22,793 common unitholders.
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units trade on the NASDAQ Global Select Market under the ticker symbol “DMLP”. As of December 31, 2025, there were 22,832 common unitholders.
In 2024, the maximum number of common units that could be purchased under the Equity Incentive Program is 131,812 common units. (2) Open-market purchases by the Operating Partnership, an affiliate of the Partnership, pursuant to a Rule 10b5-1 plan adopted on November 5, 2024 for the purpose of satisfying equity awards to be granted pursuant to the Equity Incentive Program.
In 2025, the maximum number of common units that could be purchased under the Equity Incentive Program is 157,641 common units. (2) Open-market purchases by the Operating Partnership, an affiliate of the Partnership, pursuant to a Rule 10b5-1 plan adopted on November 12, 2025, for the purpose of satisfying equity awards to be granted pursuant to the Equity Incentive Program.
Performance Graph The Performance Graph below compares the cumulative five-year total unitholder return on our common units beginning December 31, 2019 and for each subsequent year end through and including December 31, 2024, with cumulative returns of the S&P 500 Index and an industry peer group selected by us.
Performance Graph The Performance Graph below compares the cumulative five-year total unitholder return on our common units beginning December 31, 2020, and for each subsequent year end through and including December 31, 2025, with cumulative returns of the S&P 500 Index, the SPDR S&P Oil and Gas Exploration and Production ETF (“XOP”), and an industry peer group selected by us.
The industry peer group we selected is comprised of the following companies: Black Stone Minerals, L.P., Viper Energy, Inc., Sitio Royalties Corp., and Kimbell Royalty Partners, L.P. The Performance Graph assumes $100 was invested in our common units and in each of the other indices described above on December 31, 2019.
The industry peer group we selected is comprised of the following companies: Black Stone Minerals, L.P., Viper Energy, Inc., and Kimbell Royalty Partners, L.P. In prior years, we compared our cumulative five-year total unitholder return to an industry peer group selected by us that we believed appropriately reflected the minerals and royalties industry.
Distribution or dividend reinvestments have been assumed on the payment dates.
The Performance Graph assumes $100 was invested in our common units and in the index and industry peer group described above on December 31, 2020. Distribution or dividend reinvestments have been assumed on the payment dates.
Added
Over time, however, consolidation within the minerals and royalties industry has resulted in a smaller, less stable set of entities. As a result, the composition of the industry peer group has changed frequently and has introduced volatility that we believe no longer provides a consistent or meaningful basis for comparison.
Added
Beginning with this year’s performance graph, we have selected the XOP index for comparison. XOP represents a broader and more stable industry benchmark composed of a diversified set of oil and natural gas exploration companies. We believe use of this index enhances comparability and provides unitholders with a more consistent, long-term measure of our relative total unitholder return performance.

Item 7. Management's Discussion & Analysis

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

40 edited+2 added−11 removed39 unchanged
Biggest changeSignificant results include the following: ● Net income of $92.4 million; ● Distributions of $146.5 million to our limited partners; ● Acquisition of mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership's registration statements on Form S-4; ● Acquisition of overriding royalty interests representing approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership valued at $16.0 million and issued pursuant to the Partnership's registration statement on Form S-4; ● Acquisition of mineral interests representing approximately 1,485 net royalty acres located in two counties in Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at $17.0 million and issued pursuant to the Partnership's registration statement on Form S-4; and ● First payments on 1,943 gross and 12 net new wells on our Royalty Properties, of which 1,240 gross and eight net wells were attributable to our 2023 and 2024 acquisitions, and 146 gross and two net new wells on our NPI properties.
Biggest changeSignificant results include the following: ● Net income of $57.4 million; ● Distributions of $132.0 million to our limited partners; ● Acquisition of mineral interests representing approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership valued at $23.0 million and issued pursuant to the Partnership's registration statement on Form S-4; ● First payments on 761 gross and 5 net new wells on our Royalty Properties, of which 250 gross and three net wells were attributable to our 2024 and 2025 acquisitions, and on 108 gross and one net new wells on our NPI properties.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
During the period October 2023 through September 2024, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash, as defined in "Item 1 – Business". 30 Table of Contents Fourth Quarter 2024 Distribution Indicated Price In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable.
During the period October 2024 through September 2025, our Partnership's quarterly distribution payments to limited partners were based on all of its available cash, as defined in "Item 1 – Business". 30 Table of Contents Fourth Quarter 2025 Distribution Indicated Price In an effort to provide information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Objective The following discussion summarizes our results of operations and liquidity and capital resources for the fiscal years ended December 31, 2024 and 2023 and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS Objective The following discussion summarizes our results of operations and liquidity and capital resources for the fiscal years ended December 31, 2025, and 2024, and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes included elsewhere in this Annual Report.
Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and NPIs (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves.
Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and NPI (other than cash proceeds received by the Partnership from a public or private offering of securities of the Partnership) less certain expenses and reasonable reserves.
Estimates of uncollected revenues and unpaid expenses from Royalty Properties (which are interests in oil and natural gas leases that give the Partnership the right to receive a portion of the production from the leased acreage, without bearing the costs of such production) and net profits overriding royalty interests (referred to as the Net Profits Interest, or “NPI”) operated by nonaffiliated entities are particularly subjective due to our inability to gain accurate and timely information.
Estimates of uncollected revenues and unpaid expenses from Royalty Properties (which are interests in oil and natural gas leases that give the Partnership the right to receive a portion of the production from the leased acreage, without bearing the costs of such production) and net profits overriding royalty interests (referred to as the “Net Profits Interest”, or “NPI”) operated by nonaffiliated entities are particularly subjective due to our inability to gain accurate and timely information.
This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. For the year ended December 31, 2024, the reimbursement amounts actually paid or reserved did not exceed the limitation. 31 Table of Contents
This reimbursement is limited to an amount equal to the sum of 5% of our distributions plus certain costs previously paid. For the year ended December 31, 2025, the reimbursement amounts actually paid or reserved did not exceed the limitation. 31 Table of Contents
A discussion of results of operations and liquidity and capital resources for fiscal year 2022 has been omitted from this report but may be found at “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2023, filed with the SEC on February 22, 2024, and is incorporated by reference in this report from such prior Annual Report on Form 10-K.
A discussion of results of operations and liquidity and capital resources for fiscal year 2023 has been omitted from this report but may be found at “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” of our Annual Report on Form 10-K for the fiscal year ended December 31, 2024, filed with the SEC on February 20, 2025, and is incorporated by reference in this report from such prior Annual Report on Form 10-K.
Final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023. 28 Table of Contents Texas Margin Tax Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute.
Final settlement net cash received, net of capitalized transaction costs paid, of $0.2 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2025. 28 Table of Contents Texas Margin Tax Texas imposes a franchise tax (commonly referred to as the Texas margin tax) at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas margin tax statute.
We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including recent acquisitions and suspense releases on new wells. General and administrative expenses increased 7% from 2023 to 2024.
We adjust our depletion rate each quarter for significant changes in our estimates of oil and natural gas reserves, including recent acquisitions and suspense releases on new wells. General and administrative expenses increased 12% from 2024 to 2025.
These payments were included in the fourth quarter distribution paid February 13, 2024 and are excluded from this 2024 analysis. Royalty Properties Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others.
These payments were included in the fourth quarter distribution paid February 12, 2026, and are excluded from this 2025 analysis. Royalty Properties Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others.
While the relationship between the Partnership's cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments. Cash receipts attributable to the Partnership's Royalty Properties during the 2024 fourth quarter totaled $34.9 million.
While the relationship between the Partnership's cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by prior period adjustments. Cash receipts attributable to the Partnership's Royalty Properties during the fourth quarter of 2025 totaled $32.2 million.
The wells were located in 53 counties and parishes in eight states with the majority of the activity concentrated in the Permian Basin, Bakken region, South Texas, and the Rockies. Included in these totals are wells in which we own both a royalty interest and a net profits overriding royalty interest.
The wells were located in 43 counties and parishes in seven states with the majority of the activity concentrated in the Permian Basin, the Rockies, and the Bakken region. Included in these totals are wells in which we own both a royalty interest and a net profits overriding royalty interest.
Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of reserves extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion.
Depreciation, depletion and amortization increased 56% from 2024 to 2025. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of reserves extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion.
Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.9 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $1.8 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2025.
The Operating Partnership made NPI payments to us totaling $23.9 million during October 2023 through September 2024, which payments reflected 96.97% of total net proceeds of $24.6 million realized from September 2023 through August 2024. Net proceeds realized by the Operating Partnership during September through November 2024 were reflected in NPI payments made during October through December 2024.
The Operating Partnership made NPI payments to us totaling $18.3 million during October 2024 through September 2025, which payments reflected 96.97% of total net proceeds of $18.9 million realized from September 2024 through August 2025. Net proceeds realized by the Operating Partnership during September through November 2025 were reflected in NPI payments made during October through December 2025.
We intend for this discussion to provide the reader with information that will assist in understanding our consolidated financial statements, the changes in certain key items in those consolidated financial statements from period to period, and the primary factors that accounted for those changes. 2024 Overview Our results during 2024 were mainly driven by increases in Royalty Properties sales volumes from continued drilling activity in the Permian Basin and Bakken region and incremental production from 2023 and 2024 acquisitions, offset by decreases in NPI sales volumes, leasing activity, and lower industrywide realized natural gas sales prices versus 2023.
We intend for this discussion to provide the reader with information that will assist in understanding our consolidated financial statements, the changes in certain key items in those consolidated financial statements from period to period, and the primary factors that accounted for those changes. 2025 Overview Our results during 2025 were mainly driven by lower industrywide realized oil prices versus 2024, decreases in NPI properties oil and natural gas sales volumes due to lower drilling activity in the Bakken region, and increased capital expenditures deducted under the NPI calculation, offset by increases in Royalty Properties oil and natural gas sales volumes from incremental production from 2024 and 2025 acquisitions and continued drilling activity in the Rockies, increased leasing activity, and higher industrywide realized natural gas sales prices versus 2024.
Final settlement net cash received, net of capitalized transaction costs paid, of $0.2 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.
Final settlement net cash received, net of capitalized transaction costs paid, of $1.9 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2025.
Proceeds received by us from the Royalty Properties during October through December 2024 became part of the fourth quarter distribution paid in early 2025, which is excluded from this 2024 analysis. Distribution Determinations The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement.
Proceeds received by us from the Royalty Properties during October through December 2025 became part of the fourth quarter distribution paid on February 12, 2026, and are excluded from this 2025 analysis. Distribution Determinations The actual calculation of distributions is performed each calendar quarter in accordance with our partnership agreement.
The decrease in oil sales volumes attributable to our NPI properties during 2024 versus 2023 is primarily the result of lower suspense releases on new wells in the Permian Basin, partially offset by increased baseline production in the Permian Basin and Bakken region and higher suspense releases on new wells in the Bakken region.
The decrease in oil and natural gas sales volumes attributable to our NPI properties during 2025 versus 2024 is primarily the result of decreased baseline production and lower suspense releases on new wells in the Permian Basin and Bakken region, partially offset by increased suspense releases on existing wells in the Permian Basin in the second and third quarters of 2025 versus 2024.
After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2023 through September 2024 were $128.0 million, of which $122.9 million (96%) was distributed to the limited partners and $5.1 million (4%) was distributed to the General Partner.
After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 2024 through September 2025 were $118.6 million, of which $113.9 million (96%) was distributed to the limited partners and $4.7 million (4%) was distributed to the General Partner.
The decrease is primarily due to lower NPI payment receipts and lower lease bonus receipts, partially offset by higher revenue receipts attributable to our Royalty Properties, net of production and operating expenses. 27 Table of Contents Acquisitions for Units On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership, Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership’s registration statements on Form S-4.
On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership, Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and Carrollton Royalty, LP, a Texas limited partnership, the Partnership acquired mineral, royalty, and overriding royalty interests in producing and non-producing oil and natural gas properties representing approximately 14,225 net mineral acres located in 14 counties across New Mexico and Texas in exchange for 6,721,144 common units representing limited partnership interests in the Partnership valued at $202.6 million and issued pursuant to the Partnership’s registration statements on Form S-4.
Approximately 68% of these receipts reflect oil sales during September 2024 through November 2024 and natural gas sales during August 2024 through October 2024, and approximately 32% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 2024 fourth quarter were $64.25/bbl and $1.22/mcf, respectively.
Approximately 62% of these receipts reflect oil sales during September 2025 through November 2025 and natural gas sales during August 2025 through October 2025, and approximately 38% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 2025 fourth quarter were $54.98/bbl and $1.91/mcf, respectively.
Cash receipts attributable to the Partnership's NPI during the 2024 fourth quarter totaled $5.4 million. Approximately 61% of these receipts reflect oil and natural gas sales during August 2024 through October 2024, and approximately 39% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $63.93/bbl and $1.24/mcf, respectively.
Cash receipts attributable to the Partnership's NPI during the fourth quarter of 2025 totaled $4.0 million. Approximately 66% of these receipts reflect oil and natural gas sales during August 2025 through October 2025, and approximately 34% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $54.47/bbl and $2.16/mcf, respectively.
The following calculation covering the period October 2023 through September 2024 demonstrates the method: In Thousands Limited General Partners Partner 4% of net cash receipts from Royalty Properties $ - $ 5,120 96% of net cash receipts from Royalty Properties 122,879 - 1% of NPI payments to our Partnership - 239 99% of NPI payments to our Partnership 23,643 - Total distributions $ 146,522 $ 5,359 Operating Partnership share (3.03% of net proceeds) 746 Total General Partner share $ 6,105 % of total 96 % 4 % In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our activities and those of the Operating Partnership during this period.
The following calculation covering the period October 2024 through September 2025 demonstrates the method: In Thousands Limited General Partners Partner 4% of net cash receipts from Royalty Properties $ - $ 4,745 96% of net cash receipts from Royalty Properties 113,864 - 1% of NPI payments to our Partnership - 183 99% of NPI payments to our Partnership 18,152 - Total distributions $ 132,016 $ 4,928 Operating Partnership share (3.03% of net proceeds) 573 Total General Partner share $ 5,501 % of total 96 % 4 % In summary, our limited partners received 96%, and our General Partner received 4% of the net cash generated by our activities and those of the Operating Partnership during this period.
The increase in natural gas sales volumes attributable to our Royalty Properties during 2024 compared to 2023 is primarily attributable to higher baseline production and higher suspense releases on new wells in the Permian Basin, suspense releases on first payments in the Permian Basin from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies from wells acquired in the first and third quarters of 2024, higher suspense releases on first payments and increased baseline production in East Texas from wells acquired in 2022, and increased baseline production in the Mid-Continent, partially offset by decreased baseline production and lower suspense releases from first payments on acquired wells in South Texas and decreased production from legacy wells in the Rockies, Fayetteville Shale, Barnett Shale, and Southeast.
The increase in natural gas sales volumes attributable to our Royalty Properties during 2025 versus 2024 is primarily a result of incremental increases in baseline production in the Permian Basin and Rockies from wells acquired in 2024 and 2025 and higher suspense releases on new wells on legacy acreage in the Rockies, partially offset by lower suspense releases on new wells on legacy acreage in the Permian Basin and lower suspense releases on new wells on legacy acreage and decreased baseline production from legacy wells in the Mid-Continent and East Texas.
The increase is primarily a result of higher proportionate oil production taxes due to higher oil sales revenue attributable to our Royalty Properties and higher proportionate post-production costs, such as compression, transportation, processing, and marketing, due to higher oil and natural gas sales volumes attributable to our Royalty Properties. Depreciation, depletion and amortization increased 62% from 2023 to 2024.
The increase is primarily a result of higher proportionate natural gas production taxes and post-production costs, such as compression, transportation, processing, and marketing, due to higher natural gas sales revenue and volumes and higher ad valorem taxes, partially offset by lower proportionate oil production taxes due to lower oil sales revenue.
Net cash provided by operating activities decreased 5% from 2023 to 2024.
Net cash provided by operating activities remained consistent from 2024 to 2025.
Years Ended December 31, Accrual basis sales volumes: 2024 2023 % Change Royalty Properties natural gas sales (mmcf) 5,680 5,110 11 % Royalty Properties oil sales (mbbls) 1,943 1,518 28 % NPI natural gas sales (mmcf) 2,134 2,301 (7 )% NPI oil sales (mbbls) 645 740 (13 )% Accrual basis average sales price: Royalty Properties natural gas sales ($/mcf) $ 1.37 $ 2.39 (43 )% Royalty Properties oil sales ($/bbl) $ 66.74 $ 67.39 (1 )% NPI natural gas sales ($/mcf) $ 1.54 $ 2.65 (42 )% NPI oil sales ($/bbl) $ 64.02 $ 67.44 (5 )% Comparison of the years ended December 31, 2024 and 2023 The increase in oil sales volumes attributable to our Royalty Properties during 2024 versus 2023 is primarily a result of higher suspense releases on new wells in the Permian Basin and Bakken region, suspense releases on first payments in the Permian Basin from wells acquired in the third quarter of 2024, higher suspense releases on first payments in the Rockies from wells acquired in the third quarter of 2024 and first quarters of 2024 and 2022, and increased baseline production in South Texas from wells acquired in 2023 and 2022, partially offset by lower suspense releases from first payments on acquired wells in South Texas and decreased baseline production in the Permian Basin, Bakken region, and the Rockies, particularly in the fourth quarter of 2024 compared to the same period of 2023.
Years Ended December 31, Accrual basis sales volumes: 2025 2024 % Change Royalty Properties natural gas sales (mmcf) 6,132 5,680 8 % Royalty Properties oil sales (mbbls) 2,002 1,943 3 % NPI natural gas sales (mmcf) 1,963 2,134 (8 )% NPI oil sales (mbbls) 621 645 (4 )% Accrual basis average sales price: Royalty Properties natural gas sales ($/mcf) $ 2.24 $ 1.37 64 % Royalty Properties oil sales ($/bbl) $ 56.99 $ 66.74 (15 )% NPI natural gas sales ($/mcf) $ 2.55 $ 1.54 66 % NPI oil sales ($/bbl) $ 57.50 $ 64.02 (10 )% Comparison of the years ended December 31, 2025 and 2024 The increase in oil sales volumes attributable to our Royalty Properties during 2025 versus 2024 is primarily a result of incremental increases in baseline production in the Permian Basin and Rockies from wells acquired in 2024 and 2025 and higher suspense releases on new wells on legacy acreage in the Rockies, partially offset by lower suspense releases on new wells on legacy acreage in the Permian Basin and Bakken region and decreased baseline production from legacy wells in the Permian Basin.
Production taxes and operating expenses increased a combined 19% from 2023 to 2024.
Production taxes and operating expenses attributable to our Royalty Properties increased a combined 9% from 2024 to 2025.
Liquidity and Working Capital Cash and cash equivalents were $42.5 million as of December 31, 2024 and $47.0 million as of December 31, 2023. 29 Table of Contents Distributions Distributions to limited partners and the General Partner related to cash receipts were as follows: In Thousands Per Unit Limited General Year Quarter Record Date Payment Date Amount Partners Partner 2023 4th January 29, 2024 February 8, 2024 $ 1.007874 $ 39,895 $ 1,517 2024 1st April 29, 2024 May 9, 2024 $ 0.781837 31,343 1,092 2024 2nd July 29, 2024 August 8, 2024 $ 0.702058 28,144 974 2024 3rd October 28, 2024 November 7, 2024 $ 0.995785 47,140 1,776 Total distributions paid in 2024 $ 146,522 $ 5,359 2024 4th February 3, 2025 February 13, 2025 $ 0.739412 $ 35,004 $ 1,291 In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.
Liquidity and Working Capital Cash and cash equivalents were $41.9 million as of December 31, 2025, and $42.5 million as of December 31, 2024. 29 Table of Contents Distributions Distributions to limited partners and the General Partner related to cash receipts were as follows: In Thousands Per Unit Limited General Year Quarter Record Date Payment Date Amount Partners Partner 2024 4th February 3, 2025 February 13, 2025 $ 0.739412 $ 35,004 $ 1,291 2025 1st May 5, 2025 May 15, 2025 $ 0.725835 34,360 1,283 2025 2nd August 4, 2025 August 14, 2025 $ 0.620216 29,361 1,125 2025 3rd November 3, 2025 November 13, 2025 $ 0.689883 33,291 1,229 Total distributions paid in 2025 $ 2.775346 $ 132,016 $ 4,928 2025 4th February 2, 2026 February 12, 2026 $ 0.755712 $ 36,467 $ 1,226 In general, the limited partners are allocated 96% of the Royalty Properties’ net receipts and 99% of NPI net receipts.
If market conditions were to change due to declines in oil prices or uncertainty created by COVID-19 or any ongoing variants and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced.
We cannot predict events that may lead to future oil and natural gas price volatility. If market conditions were to change due to declines in oil prices, uncertainty created by military conflicts, or changes in trade policy, and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced.
The decrease in lease bonus revenue from 2023 to 2024 is primarily attributable to receipt of $11.8 million from a lease and lease amendment transaction executed in 2023, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $30,000 per acre and a 25% royalty and amended an existing lease on two separate tracts of land also totaling 243 net acres in Reagan County, Texas for $18,750 per acre.
The increase in lease bonus revenue from 2024 to 2025 is primarily attributable to receipt of $3.6 million in 2025 from an extension of an existing lease, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $15,000 per acre, and receipt of $5.4 million from an assignment of leasehold interests.
On August 31, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 568 net royalty acres located in three counties in Texas in exchange for 374,000 common units representing limited partnership interests in the Partnership valued at $10.4 million and issued pursuant to the Partnership’s registration statement on Form S-4.
The lack of change is primarily due to lower NPI payment receipts, lower revenue receipts attributable to our Royalty Properties, net of production taxes and operating expenses, and higher general and administrative expenses being offset by higher lease bonus and other income. 27 Table of Contents Acquisitions for Units On August 29, 2025, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership valued at $23.0 million and issued pursuant to the Partnership’s registration statement on Form S-4.
Despite recent improvements, the current economic environment is volatile, and therefore, we cannot predict the ultimate impact that COVID-19, the ongoing military conflict between Russia and Ukraine or the ongoing conflict between Israel and Hamas will have on our liquidity or cash flows.
The current economic environment is volatile, and we cannot predict the ultimate long-term impact on our liquidity or cash flows from these factors.
Our ability to fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas market and other financial and business factors, including the evolution of COVID-19 and any ongoing variants, along with the military conflict between Russia and Ukraine and the conflict between Israel and Hamas which are beyond our control.
However, our liquidity and ability to fund future distributions may be affected by material uncertainties arising from factors beyond our control, including: ongoing global military conflicts such as those in Ukraine and the Middle East; current inflation and interest rates; political uncertainty in Venezuela; changes to tariff and import/export regulations by the United States or other countries; and prevailing economic conditions in the oil and natural gas market and other financial and business factors.
The increase is primarily attributable to higher compensation expenses due to market adjustments, increased bonuses and an expanded Equity Incentive Program designed for employee retention, and increased legal and other professional services fees, partially offset by a decrease resulting from one-time, non-recurring professional services expenses of $1.2 million related to an unsuccessful acquisition in the first nine months of 2023.
The increase is primarily attributable to increased legal and other professional services fees, higher regulatory filing fees due to the Partnership’s S-4 registration statement filing in the first quarter of 2025, increased data service and technology costs, and higher compensation expense, including an expanded Operating Partnership equity program designed for employee retention.
Wells with such overlapping interests are counted in both categories. 25 Table of Contents Critical Accounting Estimates The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United State (“U.S.
Of the $4.0 million, $3.6 million was attributable to an extension of an existing lease on 243 net acres in two tracts of land in Reagan County, Texas for $15,000 per acre and a 25% royalty. 25 Table of Contents Critical Accounting Estimates The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“U.S.
Removed
The decrease in natural gas sales volumes attributable to our NPI properties during 2024 compared to 2023 is primarily the result of lower suspense releases on new wells in the Permian Basin and Mid-Continent, partially offset by higher suspense releases on new wells in the Bakken region and increased baseline production in the Permian Basin, Bakken region, and Mid-Continent.
Added
Wells with such overlapping interests are counted in both categories; ● Assignment of leasehold interest in Upton County, Texas, with proceeds totaling $5.4 million; and ● Lease bonus of $4.0 million includes consummation of leases or extension of existing leases of our mineral interests in undeveloped properties located in 13 counties in five states.
Removed
On September 29, 2023, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired mineral and royalty interests totaling approximately 716 net royalty acres located in three counties in Texas in exchange for 494,000 common units representing limited partnership interests in the Partnership valued at $14.4 million and issued pursuant to the Partnership’s registration statement on Form S-4.
Added
We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations.
Removed
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
Removed
Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.3 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
Removed
On July 12, 2023, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 900 net royalty acres located in 13 counties and parishes across Louisiana, New Mexico, and Texas in exchange for 343,750 common units representing limited partnership interests in the Partnership valued at $11.0 million and issued pursuant to the Partnership’s registration statement on Form S-4.
Removed
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
Removed
Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.5 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.
Removed
On September 30, 2022, pursuant to a non-taxable contribution and exchange agreement with Excess Energy, LLC, a Texas limited liability company, the Partnership acquired mineral, royalty and overriding royalty interests totaling approximately 2,100 net royalty acres located in 12 counties across Texas and New Mexico in exchange for 816,719 common units representing limited partnership interests in the Partnership valued at $20.4 million and issued pursuant to the Partnership's registration statement on Form S-4.
Removed
We believe that the acquisition is considered complementary to our business. The transaction was accounted for as an acquisition of assets under U.S. GAAP. Accordingly, the cost of the acquisition was allocated on a relative fair value basis and transaction costs were capitalized as a component of the cost of the assets acquired.
Removed
We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations despite potential material uncertainties that may impact us as a result of increased oil and natural gas market volatility caused by ongoing global military conflicts, global supply chain disruptions and the recent rise in inflation and interest rates.
Removed
Although demand and market prices for oil and natural gas have remained strong due to the rising energy use and worldwide shortage of oil due to sanctions implemented on Russia, we cannot predict events that may lead to future price volatility.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

2 edited+9 added−14 removed3 unchanged
Biggest changeCustomer Credit Risk Our principal exposure to credit risk results from receivables generated by the production activities of our operators. We do not require collateral and the failure or inability of our operators to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency, or liquidation may adversely affect our financial results.
Biggest changeWe do not require collateral and the failure or inability of our operators to meet their obligations to us due to their liquidity issues, bankruptcy, insolvency, or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable.
However, we believe the credit risk associated with our operators and customers is acceptable. Volatility in commodity pricing environment and macroeconomic conditions may enhance our purchaser credit risk. See Note 2 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data” for further detail of our concentration of credit risks and significant customers.
Volatility in the commodity pricing environment and macroeconomic conditions may enhance our purchaser credit risk. See Note 2 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data” for further detail of our concentration of credit risks and significant customers.
Removed
Oil and natural gas market prices have fluctuated significantly in recent years in response to changes in the supply and demand for oil and natural gas in the market, along with domestic and international political and economic conditions.
Added
Oil and natural gas market prices have fluctuated significantly in recent years in response to factors outside of our control, including the war in Ukraine, conflicts in the Middle East, fluctuations in interest rates, global supply chain disruptions, political uncertainty in Venezuela, and actions taken by OPEC+.
Removed
In January 2020, the World Health Organization (“WHO”) announced a global health emergency because of a new strain of coronavirus (“COVID-19”) and the significant risks to the international community and economies as the virus spread globally beyond its point of origin.
Added
It is not possible for us to predict or determine how these factors might affect oil and natural gas market prices in the future. We continue to monitor factors impacting commodity supply and demand situations, including changes to tariff and import/export regulations by the United States or other countries, and assess their impact on our business.
Removed
In March 2020, the WHO classified COVID-19 as a pandemic, based on the rapid increase in exposure globally, and thereafter, COVID-19 continued to spread throughout the U.S. and worldwide.
Added
Tariffs and Trading Relationships In April 2025, the U.S. government announced a baseline tariff of 10% on products imported from all countries and an additional individualized reciprocal tariff on the countries with which the United States has the largest trade deficits, including China.
Removed
In addition, in early March 2020, oil prices dropped sharply and continued to decline, briefly reaching negative levels, as a result of multiple factors affecting the supply and demand in global oil and natural gas markets, including (i) actions taken by OPEC members and other exporting nations impacting commodity price and production levels and (ii) a significant decrease in demand due to the COVID-19 pandemic.
Added
Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, the U.S. government has announced, adjusted and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions.
Removed
Additionally, multiple variants emerged in 2021 and became highly transmissible, which contributed to additional pricing and demand volatility during 2021 to date.
Added
Continued uncertainties about tariffs and their effects on trading relationships may affect costs for and availability of raw materials or contribute to inflation in the markets in which we own properties.
Removed
However, conditions have significantly improved since 2022 with the increase in domestic vaccination programs, a reduction in global constraints and a reduced spread of COVID-19 overall, and in May 2023, the WHO determined that COVID-19 is now an established and ongoing health issue which no longer constitutes a public health emergency of international concern.
Added
Although we are continuing to monitor the economic effects of such announcements and adjustments, as well as opportunities to mitigate their related impacts, costs and other effects associated with the tariffs remain uncertain.
Removed
Nevertheless, the long term impact of COVID-19 remains uncertain.
Added
Global oil markets are contending with tariff impacts, geopolitical tensions, and oil supply dynamics, including the evolving OPEC+ production strategy and potential constraints on Iranian, Russian, and Venezuelan oil exports.
Removed
Furthermore, from 2022 through 2024, multiple global military conflicts arose, causing instability in the international economy which may lead to significant market and other disruptions, including disruptions to the oil and gas industry, significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions.
Added
It is unclear how recent volatility in commodity prices will affect changes in North American production activity and oil producers are evaluating a range of scenarios in anticipation of oil price pressure in light of the foregoing. Gas producers could prove to be beneficiaries of potentially lower associated gas production in oil-weighted basins if oil production is curtailed.
Removed
It is not possible at this time to predict or determine the ultimate consequences of these ongoing conflicts.
Added
Larger, well-capitalized producers that comprise a greater portion of present North American shale production, are better able to withstand a broader range of commodity prices. Customer Credit Risk Our principal exposure to credit risk results from receivables generated by the production activities of our operators.
Removed
As a result of the lifting of certain restrictions put in place in response to COVID-19 and the global supply shortage of oil and natural gas caused by the Russian invasion of Ukraine, in addition to other changing market conditions, oil and natural gas market prices sharply increased during the first half of 2022 followed by a slight softening in oil prices during the second half of 2022 due to higher inflation and rising interest rates.
Removed
During the first quarter of 2023, with the exception of a decline of oil prices in March in reaction to the U.S. regional bank instability, oil prices remained generally in line with those seen in the later portion of 2022.
Removed
Despite the decline in oil prices we have seen during 2023, demand and market prices for oil and natural gas remain resilient, due in part to global travel trending towards pre-COVID-19 levels and the recently announced OPEC+ production cuts. However, commodity prices have historically been volatile, and we cannot predict events which may lead to future fluctuations in these prices.
Removed
Although the WHO in May 2023 determined that COVID-19 is now an established and ongoing health issue which no longer constitutes a public health emergency of international concern, additional actions may be required in response to the COVID-19 pandemic on a national, state, and local level by governmental authorities, and such actions may further adversely affect general and local economic conditions if there is a resurgence in the spread of COVID-19.
Removed
The long term effects of COVID-19 remain uncertain. Similarly, the length, impact and outcome of the ongoing military conflicts are highly unpredictable and could lead to significant market disruptions and increased volatility in oil and natural gas prices and supply of energy resources along with instability in the global commodity and financial markets.

Other DMLP 10-K year-over-year comparisons