DMLP 10-K & 10-Q changes, risk factors and insider trading

We do not control operations and development of the Royalty Properties or the properties underlying the NPIs that the Operating Partnership does not operate,NPI, which could impact the amount of our cash distributions.

Our unitholders are not able to influence or control the operation or future development of the properties underlying the NPIs.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 NPIsNPI are under no obligation to continue operating the underlying properties. Our unitholders do not have the right to replace an operator.

Significant portionsPortions of the Royalty Properties are unleased mineral interests. With limited exceptions, we have the right to grant leases of these interests to third parties. We anticipate receiving cash payments as bonus consideration for granting these leases in most instances. Our ability to influence third parties' decisions to become our lessees with respect to these nonproducing properties is severely limited, and those decisions may be influenced by factors beyond our control, including but not limited to oil and natural gas prices, interest rates, budgetary considerations, and general industry and economic conditions.

The Operating Partnership may transfer or abandon properties that are subject to the NPIs.NPI.

Our General Partner, through the Operating Partnership, may at any time transfer all or part of the properties underlying the NPIs.NPI. Our unitholders are not entitled to vote on any transfer; however, any such transfer must also simultaneously include the NPIsNPI at a corresponding price.

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 NPIsNPI relating to the abandoned well or property.

The cash available for distribution that comes from our royalty and mineral interests, including the NPIs,NPI, is directly affected by increases in production costs and other costs. Most of these costs are outside of our control, including costs of regulatory compliance and severance and other similar taxes. Other expenditures are dictated by business necessity, such as drilling additional wells in response to the drilling activity of others.

We may experience delays in receivedreceiving 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.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources or greater access to capital. Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis. In addition, these companies may have a greater ability to continue exploration activities during periods when market prices of oil and natural gas are low. Our operators’ larger competitors may be able to better address the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which could adversely affect our operators’ competitive position. Our operators may have access to fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties. Furthermore, the oil and natural gas industry has experiencedand recentcontinues 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. In addition, we cannot guarantee our ability to acquire additional properties and to discover reserves in the future as this will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

The Operating Partnership may participate in drilling activities in limited circumstances on the properties underlying the NPIs,NPI, and third parties may undertake drilling activities on our properties. Any increases in our reserves will come from such drilling activities or from acquisitions.

Future drilling activities on our properties may not be successful. If these activities are unsuccessful, this failure could have an adverse effect on our future results of operations and financial condition. In addition, under the terms of the NPIs,NPI, the costs of unsuccessful future drilling on the working interest properties that are subject to the NPIsNPI will reduce amounts payable to us under the NPIsNPI by 96.97% of these costs.

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.

Our current strategy contemplates that we may grow through acquisitions and development of our undeveloped property. We expect to participate in discussions relating to potential acquisition and investment opportunities. If we consummate any additional acquisitions and investments, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in connection with the acquisition, unless the terms of the acquisition require approval of our unitholders. Additionally, our unitholders will bear 100% of the dilution from issuing new common units while receiving essentially 96% of the benefitbenefit, as 4% of the benefit goes to our General Partner.

A significant portion of the properties subject to the NPIsNPI are geographically concentrated, which could cause net proceeds payable under the NPIsNPI to be impacted by regional events.

A significant portion of the properties subject to the NPIsNPI are properties located in the Bakken region and Permian Basin. 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 NPIsNPI more than if the properties were more geographically diversified.

Under the terms of the NPIs,NPI, much of the economic risk of the underlying properties is passed along to us.

Under the terms of the NPIs,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. 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.NPI. However, except as described below, we are not required to pay any excess costs.

The terms of the NPIsNPI 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 NPIsNPI until all prior uncharged costs have been recovered by the Operating Partnership.

Neither we nor the Operating Partnership are fully insured against certain risks, either because such full insurance is not available or because of high premium costs. Operations that affect the properties are subject to all of the risks normally incident to the oil and natural gas business, including blowouts, cratering, explosions, and pollution and other environmental damage, any of which could result in substantial decreases in the cash flow from our royalty interests and other interests due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations. Any uninsured costs relating to the properties underlying the NPIsNPI will be deducted as a production cost in calculating the net proceeds payable to us.

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.

We and our operators increasingly rely on information technology systems to operate our respective businesses, and the oil and natural gas industry depends on digital technologies in exploration, development, production, and processing activities. Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow. Our technologies, systems, networks, including third party software, cloud services and other internally and externally hosted hardware and software platforms, and those of the operators of our properties, vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities. 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. 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. 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. 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.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. 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.

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. ForGlobal example,military after OPECconflicts and apolitical 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. 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. Thereafter, in 2021, oil and natural gas prices significantly rebounded. However, global military conflicts,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 2024.2025. 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. In the event that any wells on our properties are shut-in, restarting wells may require significant costs from our operators, and we cannot guarantee that they would be able to restart at the same level. 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.

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.activities and in turn our business.

Recently, the U.S. has had periods of high inflation.inflation and increased tariffs on foreign jurisdictions. These inflationary and tariff pressures have resulted, and may resultcontinue to result, in increases to the costs of the goods, services and labor used by our operators, which couldhas and may continue to cause their capital expenditures and operating costs to rise. 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. Sustained levels of high interest rates, whichcombined 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 have the effects of raisingraise the cost of capital and depressingdepress economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our operators’ businesses. If our operators are unable to secure the goods, services and labor necessary for their operations at reasonable costs, their exploration and development activities could be delayed or restricted, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.

The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and other requirements, such as emissions controls. Existing laws and regulations and possible future laws and 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 and may impose stringent air permit requirements or mandate the use of specific equipment or technologies to control emissions. The U.S. Environmental Protection Agency (“EPA”) continues to develop New Source Performance standards for oil and natural gas facilities. On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, on August 13, 2020, in response to an executive order by President Trump, the EPA amended the New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments, with the exception of some technical changes, thereby reinstating the prior standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on March 8, 2024, the EPA published a final rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. 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.operations, and states will be required to adopt implementing plans for existing sources consistent with EPA’s emissions guidelines. 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. 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.emissions, and compliance timeframes may be adjusted through EPA rulemakings or state plan approvals. We cannot predict the final regulatory requirements or the cost to our operators to comply with such requirements with any certainty.

In addition, on March 26, 2015, theThe Bureau of Land Management (“BLM”) publishedis aresponsible finalfor ruleprotecting governingthe hydraulicresources fracturingand managing the uses of America’s public lands. In addition, the BLM, together with the Bureau of Indian Affairs (“BIA”), provides permitting and oversight of land held in trust by the Federal government on federalbehalf of tribes and individual Indian lands.owners. 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. Also, on November 18, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane fromAs oil and natural gas operationsproduction has increased in recent years, so have the number of wells on federalBLM-managed public lands and on Indian lands.lands Onthat Marchare 28,stimulated 2017,by Presidenthydraulic Trumpfracturing signedtechniques, an executive order directingprompting the BLM to reviewregulate such activities in a manner that seeks to balance responsible development with protection of the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them. Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule. A coalition of environmentalists, tribal advocatesenvironment and thepublic Statesafety. of California filed lawsuits challenging the rule rescission. Also,Notably, 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. 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. On April 24, 2024, several states challenged the 2024 waste prevention rule in federal court, which has resulted in a preliminary injunction against the BLM enforcing the rule in North Dakota, Texas, Montana, Wyoming, and Utah. Also, on April 23, 2024, the BLM published a final rule to update its oil and gas leasing regulations, which increases bonding requirements and raises royalty rates. Each of these regulations, to the extent that they are implemented, reinstated or modified, may result in additional levels of regulation or complexity that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase costs of compliance.

Some states have become concerned about the connection between hydraulic fracturing-related activities, particularly the injection or disposal of produced water, and the increased occurrence of seismic activity, and they have adopted or are considering additional regulations regarding such activities. 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 NPIsNPI 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 NPIsNPI or delay production schedules. Certain state agencies, including those in Texas and Oklahoma, have implemented regulations authorizing the imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a temporary injection ban. For example, in Oklahoma, the Oklahoma Corporations Commission (“OCC”) has implemented a variety of measures, including the adoption of the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications and may restrict operations at existing wells. Beginning in 2013, the OCC has ordered the reduction of disposal volumes into the Arbuckle formation. More recently, the OCC directed the shut in of a number of disposal wells due to increased earthquake activity in the Arbuckle formation and imposed further disposal well volume reductions in the Covington, Crescent, Enid, and Edmond areas. The Texas Railroad Commission has also implemented measures to assess the potential for seismic activity in the vicinity of disposal wells, and it has restricted and indefinitely suspended disposal well activities in some cases. Moreover, vigorous public debate over hydraulic fracturing and shale gas production continues and has resulted in delays of well permits in some areas.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies have also evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing,fracturing and could ultimately make it more difficult or costly for our operators to perform fracturing and increase their costs of compliance and doing business.

In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge. Specifically, the IRA amends the Clean Air Act to impose a fee on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their GHG emissions to the EPA, including sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories. InIf 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 same day, President Trump also issued executive orders to encourage fossil fuel production and exploration on federal lands and waters, while moving away from renewable energy and electric vehicles. Such actions have the potential to impact prior efforts to transition the economy away from the use of fossil fuels and towards lower or zero-carbon emissions alternatives. Further, 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.

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. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels by 2030. In November 2021, in connection with Glasgow Climate Pact, the United States and other world leaders made further commitments to reduce GHG emissions, including reducing global methane emissions by at least 30 percent by 2030 from 2020 levels. More than 150 countries have now signed on to this pledge. Most recently, at the 28th Conference of the Parties in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030. Additionally, the Biden Administration announced a new climate target for the United States on December 19, 2024, which included a 61-66 percent reduction in economy-wide net greenhouse gas emissions by 2035, as compared to 2005 levels. Many state and local leaders have stated their intent to intensify efforts to support the international climate commitments. ThoughOn January 7, 2026, President Trump issued ana executive order on January 20, 2025,memorandum directing withdrawal of the United States Ambassadorfrom specified international organizations and treaties, including the UN Framework Convention on Climate Change and the Intergovernmental Panel on Climate Change, with implementation guidance to thebe Unitedissued Nations to immediately withdraw fromby the ParisSecretary Agreement,of itState. It is possible that the Paris Agreement and other domestic and international regulatory requirementswithdrawals will have an adverse effect onimpact the demand for oil and natural gas products.

It should also be noted that, recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals. Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry. While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place. The SEC published final rules on March 28, 2024, relating to the disclosure of a range of climate-related risks and other information. Several lawsuits have been filed challenging the rules. In April 2024, the SEC agreed to pause the rules to facilitate an orderly judicial resolution. On March 27, 2025, the SEC voted to end its defense of the rules requiring disclosure of climate-related risks and greenhouse gas emissions. Following the vote, the SEC staff sent a letter to the court stating that the Commission withdraws its defense of the rules and that Commission counsel are no longer authorized to advance the arguments in the brief the Commission had filed. To the extent the rules are implemented, the Partnership, our operators and/or our customers could incur increased costs related to the assessment and disclosure of climate-related information. Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors. Ultimately, these initiatives could make it more difficult to secure funding for exploration and production activities.

In connection with ongoing litigation initiated in February 2017 by the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe contesting the validity of the process used by the USACOE to permit the Dakota Access Pipeline, on July 6, 2020, the United States District Court for the District of Columbia (the “Court”) issued an order vacating the USACOE’s easement for the Dakota Access Pipeline and requiring that the pipeline be shut down by August 5, 2020. Dakota Access, LLC and the USACOE appealed the decision. On July 14, 2020, the Court of Appeals granted a temporary administrative stay, and on January 26, 2021, the Court of Appeals affirmed that part of the lower court decision vacating the USACOE’s easement while it prepares a new environmental impact statement, but reversed the lower court’s order to shut down the pipeline. Since then, both the Biden Administration and the Court have declined to shut down the pipeline, and on June 22, 2021, the Court dismissed the subject lawsuit. The Court noted, however, that future challenges were possible depending on the outcome of the ongoing environmental study, which the USACOE issued in draft form on September 8, 2023. On October 14, 2024, the Standing Rock Sioux Tribe filed a new lawsuit in the U.S. District Court for the District of Columbia, alleging that the USACOE is allowing the pipeline to operate without the necessary easement and without an appropriate environmental impact statement. The USACOE and Dakota Access Pipeline filed motions to dismiss the case on January 17, 2025,2025 thoughThe case was dismissed on March 28, 2025. The Standing Rock Sioux appealed that dismissal on May 29, 2025 and litigation is ongoing. The USACOE completed the matterfinal remainsenvironmental pending.impact study on December 19, 2025. 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 NPIsNPI we hold in the Bakken region, the region for which the Dakota Access Pipeline is intendedconsidered to be a key pipeline. The outcome of this litigation may have a material adverse effect on our Royalty and NPI revenues derived from the Bakken region based on the timing of future development of wells on, or production of oil and natural gas from, or the method and cost of transportation related to the production on the properties. We have no control over the operation of such properties.

West Texas Minerals LLC and Carrollton Mineral Partners, LP, and certain affiliates, beneficially hold, in the aggregate, approximately 6.9%5.2% of our outstanding Units. These unitholders, acting together, would be able to influence all matters requiring unitholder approval and have the right to appoint a Manager to our Board of Managers, for so long as they collectively hold an aggregate of at least 1,000,000 Units. 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.transactions.

We and our General Partner and its affiliates share, and therefore compete for, the time and effort of General Partner personnel who provide services to us. Officers of our General Partner and its affiliates do not, and are not required to, spend any specified percentage or amount of time on our business. In fact, our General Partner has a duty to manage our Partnership in the best interests of our unitholders, but it also has a duty to operate its business for the benefit of its partners. 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. Because these shared officers function as both our representatives and those of our General Partner and its affiliates and of third parties,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, or between us or our unitholders on the one hand and the third parties for which our officers also serve management functions.other. As a result of these conflicts, our General Partner and its affiliates may favor their own interests over the interests of unitholders.

If we issue additional common units, it will reduce our unitholders' proportionate ownership interest in us. This could cause the market price of the common units to fall and reduce the per unit cash distributions paid to our unitholders. In addition, if we issuedissue limited partnership units with voting rights superior to the common units, it could adversely affect our unitholders' voting power.

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. The loss of the services of anyeither 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 anyeither of these key personnel.

We generally have not requested, and do not intend to request, rulings from the Internal Revenue Service, or IRS, or state or local taxing authorities with respect to owning and disposing of our common units or other matters affecting us. It may be necessary to resort to administrative or court proceedings in an effort to sustain some or all of those conclusions or positions taken or expressed by us, and some or all of those conclusions or positions ultimately may not be sustained. 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.

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.

ForUnder taxablecurrent yearslaw, beginningwhich aftermade Decemberpermanent 31,the 201720% anddeduction endingthat was set to expire 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. Because we own only non-operated, passive mineral and royalty interests, most or all of the income that we now generate, or will generate in the future, may not be “qualifying publicly traded partnership income” eligible for the 20% deduction. If the deduction is not available, our unitholders’ tax liability from ownership and disposition of our units may be materially higher than if the deduction is available. We urge our unitholders to consult with their tax advisors regarding the availability of the 20% deduction on any income allocated from us.

A unitholder may lose hisits 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 hisits common units to a short seller to cover a short sale of common units, the unitholder may be considered as having disposed of hisits ownership of those common units for federal income tax purposes. If so, the unitholder would no longer be a partner of our Partnership for tax purposes with respect to those common units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period, any of our income, gain, loss or deduction with respect to those common units would not be reportable, and any cash distributions received for those common units would be fully taxable and may be treated as ordinary income.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017,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.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after 2017,returns, it may collect any resulting taxes (including any applicable penalties and interest) directly from us. We generally will have the ability to shift any such tax liability (including any applicable penalties and interest) to our General Partner and our unitholders in accordance with their interests in us during the year under audit, but there can be no assurance that we will be able to do so under all circumstances. If we are unable to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, our current unitholders may bear some or all of the economic burden resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.

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.

In particular, the outbreak starting in 2020 of a coronavirus (COVID-19) resulted in quarantines, restrictions on travel and a decrease in economic activity across the world, which then resulted in a decrease in demand for hydrocarbons. 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. AlthoughWhile in May 2023 the effectsWorld Health Organization (“WHO”) determined COVID-19 to be an established and ongoing health issue which no longer constitutes a public health emergency of theinternational pandemic during 2022 were not as significant as prior years, new variants continued to cause waves of COVID-19 cases aroundconcern, the world. The COVID-19 pandemic and its ongoing variants or a new global public health crisis 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. It is impossible to predict the effect of thea global public health crisis, including continued spread, or fear of continued spread, of COVID-19 and its ongoing variants globally.globally or the occurrence of a new global public health crisis of similar magnitude. 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,effect on our business, operations and financial results.

From 2022 through 2024,2025, multiple global military conflicts arose causing instability in the international economy which mayhas continuecontinued into 2025.2026. Although the length, impact and outcome of these military conflicts are highly unpredictable, an escalation or expansion of any of these conflicts could 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. It is not possible at this time to predict or determine the ultimate consequences of these ongoing conflicts.

As a public company,company and large accelerated filer, 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.expenses. The Sarbanes-Oxley Act of 2002, or the Sarbanes Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of the Nasdaq Global Select Market and other applicable securities rules and regulations impose various requirements on public companies. Our management and other personnel will need to continue to devote a substantial amount of time to comply with these requirements. Moreover, these rules and regulations have increased, and will continue to increase, our legal and financial compliance costs and will make some activities more time-consuming and costly. If, notwithstanding our efforts to comply with new or changing laws, regulations, and standards, we fail to comply, regulatory authorities may initiate legal proceedings against us, and our business may be harmed. Further, failure to comply with these laws, regulations and standards may make it more difficult and more expensive for us to obtain directors’ and officers’ liability insurance, which could make it more difficult for us to attract and retain qualified members to serve on our board of managers or committees or as members of senior management. These rules and regulations are often subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies. This could result in future uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.

These forward-looking statements are made based upon management's current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and, therefore, involve a number of risks and uncertainties. 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. Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, public health crises includingcrises, the worldwide coronavirus (COVID-19) outbreak beginningconflicts in early 2020Ukraine and itsthe ongoingMiddle variants,East, the conflictpolitical uncertainty in Ukraine, the conflict between Israel and Hamas,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.

Our results during 20242025 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 PermianRockies, Basin and Bakken region and incremental production from 2023 and 2024 acquisitions, offset by decreases in NPI sales volumes,increased leasing activity, and lowerhigher industrywide realized natural gas sales prices versus 2023.2024. Significant results include the following:

The Partnership’s consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United StateStates (“U.S. GAAP”), which requires us to make certain estimates and apply judgments that affect our financial position and results of operations as reflected in our consolidated financial statements. Actual results may differ from those estimates. The Partnership’s accounting policies are summarized in Note 2 of the Notes to Consolidated Financial Statements in “Item 8 – Financial Statements and Supplementary Data”.

Revenues from Royalty Properties and NPI are recorded under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue checks are generally received two to three months after the production month, the Partnership accrues for revenue earned but not received by estimating production volumes and product prices. 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,Interest”, or “NPI”) operated by nonaffiliated entities are particularly subjective due to our inability to gain accurate and timely information. Identified differences between our accrued revenue estimates and actual revenue received historically have not been significant.

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 natural gas sales volumes attributable to our NPI properties during 2025 versus 2024 compared to 2023 is primarily the result of decreased baseline production and lower suspense releases on new wells in the Permian Basin and Mid-Continent,Bakken region, partially offset by higherincreased suspense releases on newexisting wells in the BakkenPermian region and increased baseline productionBasin in the Permian Basin, Bakken region,second and Mid-Continent.third quarters of 2025 versus 2024.

The decreaseincrease in lease bonus revenue from 20232024 to 20242025 is primarily attributable to receipt of $11.8$3.6 million in 2025 from aan leaseextension andof leasean amendmentexisting transaction executed in 2023,lease, wherein the Partnership leased 243 net acres in two tracts of land in Reagan County, Texas for $30,000$15,000 per acreacre, and areceipt 25%of royalty$5.4 andmillion amendedfrom an existing lease on two separate tractsassignment of landleasehold also totaling 243 net acres in Reagan County, Texas for $18,750 per acre.interests.

Production taxes and operating expenses attributable to our Royalty Properties increased a combined 19%9% from 20232024 to 2024.2025. The increase is primarily a result of higher proportionate oilnatural gas 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 revenue and volumes attributableand higher ad valorem taxes, partially offset by lower proportionate oil production taxes due to ourlower Royaltyoil Properties.sales revenue.

Net cash provided by operating activities decreasedremained 5%consistent from 20232024 to 2024.2025. The decreaselack of change is primarily due to lower NPI payment receipts andreceipts, lower lease bonus receipts, partially offset by higher revenue receipts attributable to our Royalty Properties, net of production taxes and operating expenses.expenses, and higher general and administrative expenses being offset by higher lease bonus and other income.

On SeptemberAugust 30,29, 2024,2025, pursuant to a non-taxable contribution and exchange agreement with Westmultiple Texasunrelated Mineralsthird 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,parties, the Partnership acquired mineral, royalty, and overriding royaltymineral interests in producing and non-producing oil and natural gas properties representingtotaling approximately 14,2253,050 net mineralroyalty acres located in 14Adams countiesCounty, across New Mexico and TexasColorado in exchange for 6,721,144915,694 common units representing limited partnership interests in the Partnership valued at $202.6$23.0 million and issued pursuant to the Partnership’s registration statementsstatement on Form S-4. 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. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $8.8$1.8 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.2025.

On AugustMarch 31,28, 2023,2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 5681,485 net royalty acres located in threetwo counties in TexasColorado in exchange for 374,000505,369 common units representing limited partnership interests in the Partnership valued at $10.4$17.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. 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. Contributed cash delivered at closing and final settlement net cash received, net of capitalized transaction costs paid, of $0.3$4.4 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2023.2024. 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, 2024.2025.

Our primary sources of capital, on both a short-term and long-term basis, are our cash flows from the Royalty Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from the Royalty Properties and NPIsNPI (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. Additional cash requirements include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See below for the dates of cash distributions to unitholders.

We currently expect to have sufficient liquidity to fund our distributions to unitholders and operationsoperations. despiteHowever, potentialour material uncertainties that may impact us as a result of increased oilliquidity and natural gas market volatility caused by ongoing global military conflicts, global supply chain disruptions and the recent rise in inflation and interest rates. 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. Our ability to fund future distributions to unitholders 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,factors. includingWe thecannot evolutionpredict ofevents COVID-19that may lead to future oil and anynatural ongoinggas variants,price along with the military conflict between Russia and Ukraine and the conflict between Israel and Hamas which are beyond our control.volatility. If market conditions were to change due to declines in oil prices orprices, uncertainty created by COVID-19military conflicts, or anychanges ongoingin variantstrade policy, and our revenues were reduced significantly or our operating costs were to increase significantly, our cash flows and liquidity could be reduced. Despite recent improvements, theThe current economic environment is volatile, and therefore, we cannot predict the ultimate long-term 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.flows from these factors.

Revenues from the Royalty Properties are typically paid to us with proportionate severance (production) taxes deducted and remitted by others. Additionally, we generally pay ad valorem taxes, general and administrative costs, and marketing and associated costs because royalties and lease bonuses generally do not otherwise bear operating or similar costs. After deduction of the costs described above, including cash reserves, our net cash receipts from the Royalty Properties during October 20232024 through September 20242025 were $128.0$118.6 million, of which $122.9$113.9 million (96%) was distributed to the limited partners and $5.1$4.7 million (4%) was distributed to the General Partner. Proceeds received by us from the Royalty Properties during October through December 20242025 became part of the fourth quarter distribution paid inon earlyFebruary 2025,12, which2026, isand are excluded from this 20242025 analysis.

Cash receipts attributable to the Partnership's Royalty Properties during the 2024 fourth quarter of 2025 totaled $34.9$32.2 million. Approximately 68%62% of these receipts reflect oil sales during September 20242025 through November 20242025 and natural gas sales during August 20242025 through October 2024,2025, and approximately 32%38% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the Royalty Properties during the 20242025 fourth quarter were $64.25$54.98/bbl and $1.22$1.91/mcf, respectively.

Cash receipts attributable to the Partnership's NPI during the 2024 fourth quarter of 2025 totaled $5.4$4.0 million. Approximately 61%66% of these receipts reflect oil and natural gas sales during August 20242025 through October 2024,2025, and approximately 39%34% from prior sales periods. The average indicated prices for oil and natural gas sales attributable to the NPI were $63.93$54.47/bbl and $1.24$2.16/mcf, respectively.

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. 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. More recently, military actions among the United States, Israel and Iran have occurred in the first quarter ofthroughout 2026 with related disruptions to transit through the Strait of Hormuz. Additionally, Yemen has indicated a continued readiness to resume or escalate attacks on shipping and key waterways in the Red Sea corridor, particularly in response to further escalation of the conflict involving Iran. These hostilities have disrupted and may further disrupt the flow of oil, and have contributed to, and may continue to contribute to, price volatility. Although the length and impact of these ongoing and evolving conflicts are fluid and unpredictable, they have led and may continue to lead to market disruptions, including volatility in oil prices and disruptions to global trade flows. Furthermore, the withdrawal of the United Arab Emirates from OPEC and OPEC+ may further impact oil price volatility. Oil and natural gas market price volatility 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. In the event that any wells on our properties are shut-in, restarting wells may require significant costs from our operators, and we cannot guarantee that they would be able to restart at the same level. 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.

This discussion, which presents our results of operations for the three and six months ended MarchJune 31,30, 2026 and 2025, should be read in conjunction with our unaudited condensed consolidated financial statements and the accompanying notes. We intend for this discussion to provide the reader with information that will assist in understanding our financial statements, the changes in certain key items in those financial statements from period to period, and the primary factors that accounted for those changes.

As of MarchJune 31,30, 2026, we own a net profits overriding royalty interest (referred to as the “Net Profits Interest”, or “NPI”) in various properties owned by Dorchester Minerals Operating LP (the “Operating Partnership”), a Delaware limited partnership owned directly and indirectly by our General Partner. We receive a monthly payment from the NPI equaling 96.97% of the net profits actually realized by the Operating Partnership from these properties in the preceding month. In the event that costs, including budgeted capital expenditures, exceed revenues on a cash basis in a given month for properties subject to the Net Profits Interest, no payment is made, and any deficit is accumulated and reflected in the following month's calculation of net profit.

From a cash perspective, as of MarchJune 31,30, 2026, the NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, of $11.7$10.4 million.

Our profitability is affected by oil and natural gas market prices. 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, including the ongoing military conflict in Iran, fluctuations in interest rates, global supply chain disruptions, political uncertainty in Venezuela, and actions taken by OPEC+. 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.

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. Increased tariffs by the United States have led and may continue to lead to the imposition of retaliatory tariffs by foreign jurisdictions. Additionally, theThe U.S. government has announced, adjusted and rescinded multiple tariffs on severalmany foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. 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. 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.

On AugustJuly 29,31, 2025,2026, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 3,0503,100 net royalty acres located in Adamsfive County,counties Coloradoacross the Williston Basin in North Dakota in exchange for 915,694835,958 common units representing limited partnership interests in the Partnership valued at $23.0$23.1 million and issued pursuant to the Partnership’s registration statement on Form S-4. WeAt believeclosing, thatin addition to conveying mineral and royalty interests to the acquisitionPartnership, isthe consideredcontributors complementarydelivered funds to ourthe business.Partnership The transaction was accounted for asin an acquisitionamount equal to their cash receipts during the period from April 1, 2026 through June 30, 2026 of assets$3.6 undermillion, U.S.which GAAP.will Accordingly,be included in the costcalculation of the acquisitionPartnership’s wasthird allocatedquarter on2026 acash relativedistribution fairto value basis and transaction costs were capitalized as a component of the cost of the assets acquired.unitholders.

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 (collectively, the “Contributors”), 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. Final settlement net cash received, net of capitalized transaction costs paid, of $1.9$2.0 million is included in the net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the three months ended MarchJune 31,30, 2025.

Three and Six Months Ended MarchJune 31,30, 2026 as compared to Three and Six Months Ended MarchJune 31,30, 2025

The increase in oil sales volumes attributable to our Royalty Properties from the second quarter of 2025 to the same period of 2026 is primarily a result of higher suspense releases on new wells on legacy acreage in the Permian Basin, increased baseline production from legacy wells in the Permian Basin, and Rockies wells acquired in the third quarter of 2025. The increase in oil sales volumes attributable to our Royalty Properties from the first quartersix months of 2025 to the same period of 2026 is primarily a result of higher suspense releases on new wells on legacy acreage in the Permian Basin, and suspense releases on first time payments and increased baseline production from Rockies wells acquired in the third quarter of 20252025, partially offset by decreased baseline production in the Permian Basin, particularly in the first quarter of 2026 compared to the same period of 2025, and higherlower suspense releases on new wells on legacy acreage in the Permian Basin, partially offset by decreased baseline productionRockies in the Permianfirst Basin.quarter of 2026 compared to the same period of 2025. The increase in natural gas sales volumes attributable to our Royalty Properties from the second quarter and first quartersix months of 2025 to the same periodperiods of 2026 is primarily a result of higher suspense releases on new wells on legacy acreage in the Permian Basin, and suspense releases on first time payments and increased baseline production from Rockies wells acquired in the third quarter of 2025, partially offset by decreased baseline production in the Permian Basin and lower suspense releases on new wells on legacy acreage in the Rockies in the first quarter of 2026 compared to the same period of 2025.

The increase in oil sales volumes attributable to our NPI properties from the second quarter of 2025 to the same period of 2026 is primarily a result of higher suspense releases on new wells in the Permian Basin and increased baseline production in the Bakken region and Rockies, partially offset by decreased baseline production on legacy wells in the Permian Basin. The increase in oil sales volumes attributable to our NPI properties from the first quartersix months of 2025 to the same period of 2026 is primarily duea toresult of higher suspense releases on new wells in the Permian Basin and Bakken region, increased baseline production in the Bakken region and Rockies, and the recognition of sales volumes from July 2021 through May 2025 associated with the $15.5 million of legal settlement proceeds received by the Operating Partnership in the first quarter of 2026 from resolution of ordinary course litigation affecting certain leasehold in Midland County, Texas, which is owned by the Operating Partnership and subject to the NPINPI. .This increase was partially offset by decreased baseline production on legacy wells in the Permian Basin. The increase in natural gas sales volumes attributable to our NPI properties forfrom the second quarter of 2025 to the same period of 2026 is primarily a result of increased baseline production in the Permian Basin, Bakken region, and Mid-Continent. The increase in natural gas sales volumes attributable to our NPI properties from the first quartersix months of 2025 to the same period of 2026 is primarily due to the recognition of sales volumes from July 2021 through May 2025 associated with legal settlement proceeds noted above,above and increased baseline production in the Bakken region and Mid-Continent in the second quarter of 2026 compared to the same period of 2025, partially offset by decreased baseline production on legacy wells in the Permian Basin.Basin, particularly in the first quarter of 2026 compared to the same period of 2025.

Operating costs, including production taxes, attributable to our Royalty Properties remainedincreased consistent123% from the second quarter of 2025 to the same period of 2026 and 46% from the first quartersix months of 2025 to the same period of 2026. This is primarily a result of higher proportionate oil production taxes due to higher oil sales revenue, higher post-production costs, such as compression, transportation, processing, and marketing, due to higher oil and natural gas sales volumes, and higher ad valorem taxes, partially offset by lower proportionate natural gas production taxes due to lower natural gas sales revenue and lower ad valorem taxes.revenue.

Depreciation, depletion and amortization increased 21%8% from the second quarter of 2025 to the same period of 2026 and 17% from the first quartersix months of 2025 to the same period of 2026. 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. 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.

Net cash provided by operating activities decreasedincreased 28%38% from the first quartersix months of 2025 to the same period of 2026 primarily due to lowerhigher revenue receipts attributable to our Royalty Properties and lowerhigher NPI payment receipts, partially offset by higherlower lease bonus receipts and lowerhigher general and administrative expenses.expense payments.

Cash receipts attributable to our Royalty Properties during the thirdsecond quarter of 2026 totaled $26.6$50.4 million. Approximately 76%66% of these receipts reflect oil sales during DecemberMarch 20252026 through FebruaryMay 2026 and natural gas sales during NovemberFebruary 20252026 through JanuaryApril 2026, and approximately 24%34% from prior sales periods. The average realized prices for oil and natural gas sales cash receipts attributable to the Royalty Properties during the firstsecond quarter of 2026 were $51.79$70.37/bbl and $2.27$1.68/mcf, respectively.

Our primary sources of capital, on both a short-term and long-term basis, are our cash flows from the Royalty Properties and the NPI. Our partnership agreement requires that we distribute quarterly an amount equal to all funds that we receive from 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. Additional cash requirements include the payment of oil and natural gas production and property taxes not otherwise deducted from gross production revenues and general and administrative expenses incurred on our behalf and allocated to the Partnership in accordance with the partnership agreement. Because the distributions to our unitholders are, by definition, determined after the payment of all expenses actually paid by us, the only cash requirements that may create liquidity concerns for us are the payment of expenses. Because many of these expenses vary directly with oil and natural gas sales prices and volumes, we anticipate that sufficient funds will be available at all times for payment of these expenses. See Note 5 to the unaudited condensed consolidated financial statements included in “Item 1 – Financial Statements” of this Quarterly Report for additional information regarding cash distributions to unitholders.

The Partnership leases its office space at 3838 Oak Lawn Avenue, Suite 300, Dallas, Texas, through an operating lease (the “Office Lease”). The third amendment to our Office Lease was executed in April 2017 for a term of 129 months, beginning June 1, 2018 and expiring February 28, 2029. The fourth amendment to our Office Lease was executed in 2029.May 2026 for a term of 86 months, beginning March 1, 2029 and expiring April 30, 2036. Under the third amendmentand fourth amendments to the Office Lease, monthly rental payments range from $25,000 to $30,000.$52,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations as of March 31, 2026 are summarized asin follows:Note 7 to the unaudited condensed consolidated financial statements included in “Item 1 – Financial Statements” of this Quarterly Report.

We currently expect to have sufficient liquidity to fund our distributions to unitholders and operations. 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 EastEast, including the conflict in Iran; 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. 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 current economic environment is volatile, and we cannot predict the ultimate long-term impact on our liquidity or cash flows from these factors.

Cash and cash equivalents totaled $28.2$72.5 million at MarchJune 31,30, 2026 and $41.9 million at December 31, 2025.

As of MarchJune 31,30, 2026, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our Annual Report.