DORCHESTER MINERALS, L.P.

Properties

We own two categories of properties: Royalty Properties and net profits overriding royalty interests (referred to as the “Net Profits Interest”, or “NPI”).

Royalty Properties

We own Royalty Properties representing producing and nonproducing mineral, royalty, overriding royalty, net profit and leasehold interests in properties located in 594 counties and parishes in 28 states. Acreage amounts listed herein represent our best estimates based on information provided to us as a royalty owner. Due to the significant number of individual deeds, leases and similar instruments involved in the acquisition and development of the Royalty Properties by us or our predecessors, acreage amounts are subject to change as new information becomes available. In addition, as a royalty owner, our access to information concerning activity and operations on the Royalty Properties is limited. Most of our producing properties are subject to old leases and other contracts pursuant to which we are not entitled to well information. Some of our newer leases provide for access to technical data and other information. We may have limited access to public data in some areas through third party subscription services. 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.

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.

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. Consequently, net acreage ownership in these categories is not determinable. Our net interest in production from properties in which we own a royalty or overriding royalty interest may be affected by royalty terms negotiated by the previous mineral interest owners in such tracts and their lessees. Our interest in the majority of these properties is perpetual in nature. However, a minor portion of the properties are subject to terms and conditions pursuant to which a portion of our interest may terminate upon cessation of production.

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.

State · Gross · Net · State · Gross · Net

Alabama · 105,000 · 8,000 · Montana · 366,000 · 81,000

Arkansas · 49,000 · 16,000 · Nebraska · 3,000 · < 500

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 · < 500 · < 500

Illinois · 5,000 · 1,000 · Oklahoma · 273,000 · 19,000

Indiana · < 500 · < 500 · 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 · < 500

Mississippi · 81,000 · 9,000 · West Virginia · < 500 · < 500

Missouri · < 500 · < 500 · Wyoming · 32,000 · 2,000

Leasing Activity

We received $4.0 million during 2025 attributable to lease bonuses from new leases, extensions of existing leases, and pooling elections. These leases reflected bonus payments ranging up to $15,000/acre and initial royalty terms ranging up to 25%. The following table sets forth a summary of new leases, lease extensions, and pooling elections consummated during 2023, 2024 and 2025.

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.

(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.

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. 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. 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.

• Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators’ ability to succeed.
• Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition.
• Our ability to identify and capitalize on acquisitions is limited by contractual provisions and substantial competition.
• Any future acquisitions will involve risks that could adversely affect our business, which our unitholders generally will not have the opportunity to evaluate.
• A natural disaster or catastrophe could damage pipelines, gathering systems and other facilities that service our properties, which could substantially limit our operations and adversely affect our cash flow.
• 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.
• Under the terms of the NPI, much of the economic risk of the underlying properties is passed along to us.
• Our cash flow is subject to operating hazards and unforeseen interruptions for which we may not be fully insured.
• Governmental policies, laws and regulations could have an adverse impact on our business and cash distributions.
• 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.
• The Partnership may be adversely affected by price volatility in the oil and natural gas markets.
• 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.
• Regulatory and Environmental Risk Factors
• Environmental costs and liabilities and changing environmental regulation could affect our cash flow.
• The potential adoption of federal and state hydraulic fracturing laws or executive orders could delay or restrict development of our oil and natural gas properties.
• Climate change legislation or regulations could result in increased operating costs and reduced demand for the oil and natural gas production from our properties.
• Our oil and natural gas reserve data and future net revenue estimates are uncertain.
• The outcome of pending litigation related to the Dakota Access Pipeline and any related executive orders could have a material adverse effect on our revenue and cash distributions.
• Risks Inherent in an Investment in Our Common Units
• Cost reimbursement due our General Partner may be substantial and reduce our cash available to distribute to our unitholders.
• Our net income as reported for tax and financial statement purposes may differ significantly from our cash flow that is used to determine cash available for distributions.
• Our unitholders have limited voting rights and do not control our General Partner, and their ability to remove our General Partner is limited.
• The control of our General Partner may be transferred to a third party without unitholder consent.
• A group of unitholders own a large percentage of our units and have the right to appoint a Manager to our Board of Managers and may be able to exert significant influence over certain matters.
• 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.
• We may issue additional securities, diluting our unitholders' interests.
• Our unitholders may not have limited liability in the circumstances described below and may be liable for the return of certain distributions.
• We are dependent upon key personnel, and the loss of services of any of our key personnel could adversely affect our operations.
• We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.
• Tax Risk Factors
• The tax consequences to a unitholder of the ownership and sale of common units will depend in part on the unitholder’s tax circumstances. Each unitholder should consult such unitholder’s own tax advisor about the federal, state and local tax consequences of the ownership of common units.
• We generally do not obtain rulings or assurances from the IRS or state or local taxing authorities on matters affecting us.
• 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.
• The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.
• 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.
• The IRS could reallocate items of income, gain, deduction and loss between transferors and transferees of common units if the IRS does not accept our monthly convention for allocating such items.
• Our unitholders may not be able to deduct losses attributable to their common units.
• Our unitholders’ partnership tax information may be audited.
• Our unitholders may have more taxable income or less taxable loss with respect to their common units if the IRS does not respect our method for determining the adjusted tax basis of their common units.
• Tax-exempt investors may recognize unrelated business taxable income.
• Tax consequences of certain NPIs are uncertain.
• Our unitholders may not be entitled to deductions for percentage depletion with respect to our oil and natural gas interests.
• Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our method of allocating depletion deductions.
• Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our method of determining a unitholder's share of the basis of partnership property.
• The ratio of the amount of taxable income that will be allocated to a unitholder to the amount of cash that will be distributed to a unitholder is uncertain, and cash distributed to a unitholder may not be sufficient to pay tax on the income we allocate to a unitholder.
• 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.
• Foreign, state and local taxes could be withheld on amounts otherwise distributable to a unitholder.
• 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.
• Our unitholders may be subject to withholding tax upon transfers of their common units.
• General Risk Factors
• Public health threats could have an adverse effect on our Partnership, our cash flow and our industry.
• The Partnership may be adversely affected by the international economic instability caused by ongoing global conflicts.
• We will continue to incur increased costs as a result of operating as a public company, and our management will continue to devote substantial time to compliance with our public company responsibilities and corporate governance practices.
• Disclosure Regarding Forward-Looking Statements