DORCHESTER MINERALS, L.P.

Description of the Business

Dorchester Minerals, L.P. (the “Partnership”) is a publicly traded Delaware limited partnership that commenced operations on* January 31, 2003.Our Partnership is based in Dallas, Texas and our business may*be described as the acquisition, ownership and administration of Royalty Properties (which consists of producing and nonproducing mineral, royalty, overriding royalty, net profits, and leasehold interests located in 594 counties and parishes in 28 states (“Royalty Properties”)) and net profits overriding royalty interests (referred to as the “Net Profits Interest”, or “NPI”). In these Notes, the term “Partnership,” as well as the terms “us,” “our,” “we,” and “its” are sometimes used as abbreviated references to Dorchester Minerals, L.P. itself or Dorchester Minerals, L.P. and its related entities.

Basis of Presentation

The consolidated financial statements herein have been prepared in accordance with accounting principles generally accepted in the United States (“U.S. GAAP”). The consolidated financial statements include the accounts of Dorchester Minerals, L.P., Dorchester Minerals Oklahoma, LP, Dorchester Minerals Oklahoma GP, Inc., Maecenas Minerals LLP, Dorchester-Maecenas GP LLC, The Buffalo Co., A Limited Partnership, and DMLPTBC GP LLC, and DMLP Terra Firma LLC. All intercompany balances and transactions have been eliminated in consolidation.

Certain amounts in the prior‑period consolidated financial statements have been reclassified to conform to the current‑period presentation. Management believes these reclassifications enhance the clarity and consistency of the financial statement presentation. These are presentation only reclassifications and hadno effect on total assets, total liabilities, shareholders’ equity, net income, or cash flows for any periods presented.

Basic and Diluted Earnings Per Unit—* Per-unit information is calculated by dividing the net income applicable to holders of our Partnership’s common units by the weighted average number of units outstanding. The Partnership hasno potentially dilutive securities and, accordingly, basic and dilutive net income per unit donot* differ.

Use of Estimates— The preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Partnership evaluates these estimates on an ongoing basis, using historical experience, consultation with experts and other methods the Partnership considers reasonable in each circumstance. Any effects on the Partnership’s business, financial position, or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known. Although the Partnership believes these estimates are reasonable, actual results could differ from those estimates.

General Partner— Our* general partner is Dorchester Minerals Management LP, referred to in these Notes as “our General Partner.” Our General Partner owns all of the partnership interests in Dorchester Minerals Operating LP, the Operating Partnership. See Note4* —Related Party Transactions. The General Partner is allocated 4% and 1% of our Royalty Properties’ net revenues and Net Profits Interest (“NPI”) proceeds received by the Operating Partnership, respectively.

Cash and Cash Equivalents— Our* principal banking relationships are with major financial institutions. Cash balances in these accounts may,** at times, exceed federally insured limits. We havenot* experienced any losses in such cash accounts and donot believe we are exposed to any significant risk on cash and cash equivalents. Short term investments with an original maturity ofthree months or less are considered to be cash equivalents and are carried at cost, which approximates fair value.

Concentration of Credit Risks and Significant Customers— Our* Partnership, as a royalty owner, hasno* control over the volumes or method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI. Royalties operating revenues from properties operated by Exxon Mobil Corporation and its subsidiaries and Chevron Corporation and its subsidiaries represented approximately 15% and 10% of total operating revenues for the year ended* December 31, 2025*, respectively. Royalties operating revenues from properties operated by Exxon Mobil Corporation and its subsidiaries and Diamondback Energy, Inc. represented approximately 16% and 15% of total operating revenues for the year ended* December 31, 2024,respectively. Royalties operating revenues from properties operated by Pioneer Natural Resources Company represented approximately 11% of total operating revenues for the year ended December 31, 2023.If we were to lose a significant customer, such loss could impact revenue. The loss of any single customer is mitigated by our diversified customer base, and we donot* believe that the loss of any single customer would have a long-term material adverse effect on our financial position or the results of operations.

Fair Value of Financial Instruments— The carrying amount of cash and cash equivalents, trade and other receivables, net profits interest receivable - related party, and accounts payables and other current liabilities approximates fair value because of the short maturity of those instruments. These estimated fair values* may**not* be representative of actual values of the financial instruments that could have been realized as of year-end or that will be realized in the future.

Receivables— Our* Partnership’s accounts receivable and net profits interest receivable consist primarily of Royalty Properties payments receivable and NPI payments receivable, respectively. Most payments are receivedtwo* tothree months after the production date. No reserve for current expected credit losses on accounts receivable is deemed necessary based upon our lack of historical write offs and review of current receivables. The Partnership’s receivables as of the years ended* December 31, 2025,*2024 and2023 consists of the following:

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Oil and Natural Gas Properties—* We utilize the full cost method of accounting for costs related to our oil and natural gas properties. Under this method, all such costs are capitalized and amortized on an aggregate basis over the estimated lives of the properties using the unit-of-production method. These capitalized costs are subject to a ceiling test, which limits such pooled costs to the aggregate of the present value of future net revenues attributable to proved oil and natural gas reserves discounted at 10% plus the lower of cost or market value of unproved properties. For the purposes of determining the capitalized costs ceiling, our Partnership only assigned value to proved developed producing oil and natural gas reserves as of December 31, 2025*.* The full cost ceiling is evaluated at the end of each quarter and when events indicate possible impairment. There have beenno impairments for the years ended December 31, 2025,*2024 and2023 as a result of the full cost ceiling test.

The discounted present value of our proved oil and natural gas reserves is a major component of the ceiling test calculation and requires many subjective judgments. Estimates of reserves are forecasts based on engineering and geological analyses. Different reserve engineers could reach different conclusions as to estimated quantities of oil and natural gas reserves based on the same information. The passage of time provides more qualitative and quantitative information regarding reserve estimates, and revisions are made to prior estimates based on updated information. However, there can beno assurance that more significant revisions willnot be necessary in the future. Significant downward revisions could result in an impairment representing a non-cash charge to income. In addition to the impact on the calculation of the ceiling test, estimates of proved reserves are also a major component of the calculation of depletion.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas reserves that are included in the discounted present value of our reserves are objectively determined. The ceiling test calculation requires use of the unweighted arithmetic average of thefirst day of the month price during the12-month period ending on the balance sheet date and costs in effect as of the last day of the accounting period, which are generally held constant for the life of the oil and natural gas properties. As a result, the present value isnot necessarily an indication of the fair value of the reserves. Oil and natural gas prices have historically been volatile, and the prevailing prices at any given time* may**not* reflect our Partnership’s or the industry’s forecast of future prices.

Gains and losses are recognized upon the disposition of oil and natural gas properties involving a significant portion (greater than 25%) of our Partnership’s reserves. Proceeds from other dispositions of oil and natural gas properties are credited to the full cost pool.

Leasehold Improvements —* *Leasehold improvements are amortized over the shorter of their estimated useful lives or the related life of the lease.

Leases—* The Partnership determines if an arrangement is a lease at inception. The Partnership leases its office space at3838* Oak Lawn Avenue, Suite300, Dallas, Texas, through an operating lease (the “Office Lease”). The operating lease is included in operating lease right-of-use (“ROU”) asset and operating lease liability in our consolidated balance sheets. Operating lease expense is included in general and administrative expenses in the consolidated income statements.

Operating lease ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. As the Partnership’s lease doesnot provide an implicit rate of return and as the Partnership is precluded from incurring any borrowings above a nominal amount under its partnership agreement, the Partnership used a discount rate commensurate with the incremental borrowing rate of a group of peers based on information available at the application date in determining the present value of lease payments. Lease expense for minimum lease payments is recognized on a straight-line basis over the lease term.

Asset Retirement Obligations— Based on the nature of our property ownership, we haveno material obligations to record.

Revenue Recognition— The pricing of oil and natural gas sales from the Royalty Properties and NPI is primarily determined by supply and demand in the marketplace and can fluctuate considerably. As a royalty owner, we haveno operational control over the volumes and method of sale of oil and natural gas produced and sold from the Royalty Properties and NPI.

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 receivedtwo tothree months after the production month, the Partnership accrues for revenue earned butnot received by estimating production volumes and product prices. Identified differences between our accrued revenue estimates and actual revenue received historically havenot been significant.

The Partnership doesnot record revenue for unsatisfied or partially unsatisfied performance obligations. The Partnership’s right to revenues from Royalty Properties and NPI occurs at the time of production, at which point, payment is unconditional, andno remaining performance obligation exists for the Partnership. Accordingly, the Partnership’s revenue contracts for Royalty Properties and NPI donot generate contract assets or liabilities.

The following table disaggregates the Partnership’s oil and natural gas revenues from production on the Royalty Properties for the years ended* December 31, 2025,*2024 and2023:

Revenues from lease bonus payments are recorded upon receipt. The lease bonus is separate from the lease itself and is recognized as revenue to the Partnership upon receipt of payment. The Partnership generates lease bonus revenue by leasing its mineral interests to exploration and production companies and includes proceeds from assignments of leasehold interests where the Partnership retains an interest. A lease agreement represents the Partnership’s contract with a lessee and generally transfers the rights to develop oil or natural gas, grants the Partnership a right to a specified royalty interest, and requires that drilling and completion operations commence within a specified time period. Upon signing a lease agreement,no further performance obligation exists for the Partnership, and therefore,no contract assets or contract liabilities are generated.

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Income Taxes— We are treated as a partnership for income tax purposes and, as a result, our income or loss is includable in the tax returns of the individual unitholders. Depletion of oil and natural gas properties is an expense allowable to each individual partner, and the depletion expense as reported on the consolidated financial statements willnot be indicative of the depletion expense an individual partner or unitholder* may*be able to deduct for income tax purposes.

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. The Texas margin tax applies to corporations and limited liability companies, general and limited partnerships (unless otherwise exempt), limited liability partnerships, trusts (unless otherwise exempt), business trusts, business associations, professional associations, joint stock companies, holding companies, joint ventures, and certain other business entities having limited liability protection.

Limited partnerships that receive at least90% of their gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and donot receive more than10% of their income from operating an active trade or business, are generally exempt from the Texas margin tax as “passive entities.” We believe our Partnership meets the requirements for being considered a “passive entity” for Texas margin tax purposes and, therefore, it is exempt from the Texas margin tax. If the Partnership is exempt from Texas margin tax as a passive entity, each unitholder that is considered a taxable entity under the Texas margin tax would generally be required to include its portion of Partnership revenues in its own Texas margin tax computation. The Texas Administrative Code provides that such income is sourced according to the principal place of business of the Partnership, which would be the state of Texas.

Recent Accounting Pronouncements

Accounting PronouncementsNot* Yet Adopted*

In* November 2024,the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic220*-40): Disaggregation of Income Statement Expenses” (“ASU2024-03”), which requires public entities to disclosure additional information about certain costs and expenses included in relevant expense captions presented on the income statement. ASU2024-03 is effective for annual periods beginning after* December15,* 2026, and for interim periods within annual reporting periods beginning after* December15,* 2027, with early adoption permitted. Management is evaluating ASU2024-03 to determine its impact on the Partnership’s disclosures.

In* December 2025,the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”)2025-11, “Interim Reporting (Topic270*): Narrow-Scope Improvements” (“ASU2025-11”), which improves the guidance in Topic270 by improving the navigability of the required interim disclosures and clarifying when that guidance is applicable. The ASU includes a comprehensive list of required interim disclosures and adds a principle that requires entities to disclose events since the end of the last annual reporting period that have a material impact on the entity. ASU2025-11 is effective for interim reporting periods within annual reporting periods beginning after* December 15, 2027,with early adoption permitted. Management is evaluating ASU2025*-11 to determine its impact on the Partnership’s disclosures.

The Partnership considers the applicability and impact of all ASUs. There areno other recent accounting pronouncementsnot yet adopted that are expected to have a material effect on the Partnership upon adoption.

On* August29,* 2025, pursuant to a non-taxable contribution and exchange agreement with multiple unrelatedthird 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. 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 $1.8 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended* December31,* 2025. Oil and natural gas properties, at cost, on the consolidated balance sheet as of* December 31, 2025*includes $19.7 million of net capitalized costs attributable to proved oil and natural gas properties acquired in the transaction.

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. 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 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended December 31, 2024.Oil and natural gas properties, at cost, on the consolidated balance sheet as of December 31, 2024includes $193.7 million of net capitalized costs attributable to proved oil and natural gas properties acquired in the transaction. 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.*

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On* September 30, 2024,pursuant to a non-taxable contribution and exchange agreement with an unrelatedthird* 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 valued at $16.0 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 $1.4 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended* December 31, 2024.Oil and natural gas properties, at cost, on the consolidated balance sheet as of December 31, 2024*includes $14.6 million of net capitalized costs attributable to proved oil and natural gas properties acquired in the transaction.

On* March**28,* 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelatedthird parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located intwo 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. 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 $4.4 million is included in net cash contributed in acquisitions on the consolidated statement of cash flows for the year ended* December 31, 2024.Oil and natural gas properties, at cost, on the consolidated balance sheet as of December 31, 2024*includes $12.3 million of net capitalized costs attributable to proved oil and natural gas properties acquired in the transaction.

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.*

Our General Partner owns all of the partnership interests in the Operating Partnership. The Operating Partnership is the employer of all personnel, owns the working interests and other properties underlying our NPI, and provides day-to-day operational and administrative services to us and the General Partner. In accordance with our partnership agreement, we reimburse the General Partner for certain allocable general and administrative costs, including rent, salaries, and employee equity and benefit plans that arenot direct expenses. These types of reimbursements are limited to 5% of distributions, plus certain costs previously paid. All such costs have been below the annual 5% limit amount, including the allowable surplus carryforward, for the years ended* December 31, 2025,2024 and2023. Additionally, certain reimbursable direct expenses such as professional and regulatory fees, as well as certain general and administrative costs that are related to regulatory matters, arenot limited. The Partnership reimburses the Operating Partnership an estimated monthly fee for these expenses and in the month following will settle any payable or receivable remaining for actual expenses paid on behalf of the Partnership. All significant related party transactions with the Operating Partnership have been stated on the face of the consolidated financial statements for the years ended December 31, 2025,*2024 and2023.

Our Partnership and the Operating Partnership are involved in legal and/or administrative proceedings arising in the ordinary course of their businesses,none of which have predictable outcomes andnone of which are believed to have any significant effect on consolidated financial position, cash flows, or operating results.

On* January 22, 2026,the Partnership announced its cash distribution for thefourth* quarter of2025 of $0.755712 per common unit, representing activity for thethree-month period ended* December 31, 2025*, payable to common unitholders on record as of* February 2, 2026.This distribution was paid on February 12, 2026.The partnership agreement requires the next cash distribution to be paid by May 15, 2026.*

Thethird amendment to our Office Lease was executed in* April 2017for a term of 129 months, beginning June 1, 2018and expiring in2029.* At lease commencement, the Partnership concluded the Office Lease was an operating lease. Under thethird amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000 and the Partnership received lease incentives of $0.7 million.

Lease expense for the years ended* December 31, 2025,*2024 and2023 was as follows:

Supplemental cash flow information related to leases was as follows:

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Supplemental balance sheet information related to leases was as follows:

Maturities of lease liabilities are as follows:

The Partnership manages its business activities on a consolidated basis and operates in asingle operating and reportable segment. Operating segments are defined as components of a public entity that engages in business activities and for which discrete financial information and operating results are available and regularly reviewed by the chief operating decision maker in deciding how to allocate resources and assess performance. As disclosed in Note1 – Business and Basis of Presentation, our business* maybe described as the acquisition, ownership and administration of Royalty Properties and the NPI. See Note2* – Summary of Significant Accounting Policies for a summarization of the Partnerships revenue recognition policy.

The Partnership’s CEO has been determined to be the chief operating decision maker of the Partnership. The CEO uses Net income, as reported on our Consolidated Income Statements, to assess financial performance and allocate resources on a consolidated basis. The CEO manages and evaluates the results of the Partnership on a consolidated basis, and Net income is used to evaluate key operating decisions, such as making strategic acquisitions, determining transaction structures to capitalize on the development of the properties underlying our mineral interests, and allocating resources for general and administrative expenditures. The CEO doesnot review consolidated balance sheet assets when assessing segment performance and deciding how to allocate resources. Disaggregated operating revenues of the Partnership’s single segment and all significant segment expenses are presented separately on the Partnership’s Consolidated Income Statements. There areno other significant segment expenses or other segment items that would require disclosure.