The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this Quarterly Report. Objective This discussion, which presents our results of operations for the three and six months ended June 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. Overview We own producing and nonproducing mineral, royalty, overriding royalty, net profits and leasehold interests. We refer to these interests as the Royalty Properties. We currently own Royalty Properties in 593 counties and parishes in 28 states. As of June 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. In the event the NPI has a deficit of cumulative revenue versus cumulative costs, the deficit will be borne solely by the Operating Partnership. From a cash perspective, as of June 30, 2026, the NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, of $10.4 million. Commodity Price Risks The pricing of oil and natural gas sales is primarily determined by supply and demand in the global marketplace and can fluctuate considerably. As a royalty owner and non-operator, we have extremely limited access to timely information and no operational control over the volumes of oil and natural gas produced and sold or the terms and conditions on which such volumes are marketed and sold. 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. Tariffs and Trading Relationships The U.S. government has announced, adjusted and rescinded multiple tariffs on many 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. Global oil markets are contending with tariff impacts, geopolitical tensions, including the recent military conflict in Iran, and oil supply dynamics, including the evolving OPEC+ production strategy, potential constraints on Iranian, Russian, and Venezuelan oil exports, disruptions to the flow of oil through the Strait of Hormuz, and the withdrawal of the United Arab Emirates from OPEC and OPEC+. It is unclear how recent volatility in commodity prices will affect changes in North American production activity and oil producers are evaluating a range of scenarios in anticipation of oil price pressure in light of the foregoing. Gas producers could prove to be beneficiaries of potentially lower associated gas production in oil-weighted basins if oil production is curtailed. Larger, well-capitalized producers that comprise a greater portion of present North American shale production, are better able to withstand a broader range of commodity prices. 9 Table of Contents Results of Operations Acquisitions for Common Units On July 31, 2026, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral and royalty interests totaling approximately 3,100 net royalty acres located in five counties across the Williston Basin in North Dakota in exchange for 835,958 common units representing limited partnership interests in the Partnership valued at $23.1 million and issued pursuant to the Partnership’s registration statement on Form S-4. At closing, in addition to conveying mineral and royalty interests to the Partnership, the contributors delivered funds to the Partnership in an amount equal to their cash receipts during the period from April 1, 2026 through June 30, 2026 of $3.6 million, which will be included in the calculation of the Partnership’s third quarter 2026 cash distribution to unitholders. On August 29, 2025, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 3,050 net royalty acres located in Adams County, Colorado in exchange for 915,694 common units representing limited partnership interests in the Partnership valued at $23.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. 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. Final settlement net cash received of $4.0 million is included in net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the six months ended June 30, 2026. 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 $2.0 million is included in the net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the three months ended June 30, 2025. Three and Six Months Ended June 30, 2026 as compared to Three and Six Months Ended June 30, 2025 Our period-to-period changes in net income and cash flows from operating activities are principally determined by changes in oil and natural gas sales volumes and prices, and to a lesser extent, by capital expenditures deducted under the NPI calculation. Our portion of oil and natural gas sales volumes and average sales prices are shown in the following table. Oil sales volumes include volumes attributable to natural gas liquids and oil sales prices include natural gas liquids prices combined by volumetric proportions. Three Months Ended Six Months Ended June 30, June 30, Accrual basis sales volumes: 2026 2025 % Change 2026 2025 % Change Royalty Properties natural gas sales (mmcf) 1,430 1,341 7 % 3,093 2,824 10 % Royalty Properties oil sales (mbbls) 573 399 44 % 1,198 917 31 % NPI natural gas sales (mmcf) 677 493 37 % 1,318 929 42 % NPI oil sales (mbbls) 170 163 4 % 523 298 76 % Accrual basis average sales prices: Royalty Properties natural gas sales ($/mcf) $ 0.19 $ 1.39 (86 )% $ 1.49 $ 2.50 (40 )% Royalty Properties oil sales ($/bbl) $ 76.12 $ 56.51 35 % $ 67.00 $ 60.18 11 % NPI natural gas sales ($/mcf) $ 1.18 $ 2.20 (46 )% $ 2.78 $ 3.00 (7 )% NPI oil sales ($/bbl) $ 74.22 $ 61.86 20 % $ 72.83 $ 61.62 18 % Both oil and natural gas sales price changes reflected in the table above resulted from changing market conditions. 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 six 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 2025, 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 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 natural gas sales volumes attributable to our Royalty Properties from the second quarter and first six months of 2025 to the same periods 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 six months of 2025 to the same period of 2026 is primarily a result 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 NPI. 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 from 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 six 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 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, particularly in the first quarter of 2026 compared to the same period of 2025. 10 Table of Contents Operating costs, including production taxes, attributable to our Royalty Properties increased 123% from the second quarter of 2025 to the same period of 2026 and 46% from the first six 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. Depreciation, depletion and amortization increased 8% from the second quarter of 2025 to the same period of 2026 and 17% from the first six 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. General and administrative expenses increased 33% from the second quarter of 2025 to the same period of 2026. The increase is primarily attributable to higher professional services fees and increased compensation expenses, including an expanded Operating Partnership equity program designed for employee retention. General and administrative expenses increased 12% from the first six months of 2025 to the same period of 2026. The increase is primarily attributable to higher professional services fees and increased compensation expenses, including an expanded Operating Partnership equity program designed for employee retention, partially offset by lower regulatory fees due to the Partnership’s S-4 filing in the first quarter of 2025. Net cash provided by operating activities increased 38% from the first six months of 2025 to the same period of 2026 primarily due to higher revenue receipts attributable to our Royalty Properties and higher NPI payment receipts, partially offset by lower lease bonus receipts and higher general and administrative expense payments. In an effort to provide the reader with information concerning prices of oil and natural gas sales that correspond to our quarterly distributions, management calculates the average price by dividing gross revenues received by the net volumes of the corresponding product without regard to the timing of the production to which such sales may be attributable. This “realized price” does not necessarily reflect the contract terms for such sales and may be affected by transportation costs, location differentials, and quality and gravity adjustments. While the relationship between our cash receipts and the timing of the production of oil and natural gas may be described generally, actual cash receipts may be materially impacted by purchasers’ release of suspended funds and by purchasers’ prior period adjustments. Cash receipts attributable to our Royalty Properties during the second quarter of 2026 totaled $50.4 million. Approximately 66% of these receipts reflect oil sales during March 2026 through May 2026 and natural gas sales during February 2026 through April 2026, and approximately 34% from prior sales periods. The average realized prices for oil and natural gas sales cash receipts attributable to the Royalty Properties during the second quarter of 2026 were $70.37/bbl and $1.68/mcf, respectively. Cash receipts attributable to the Partnership's NPI during the second quarter of 2026 totaled $16.6 million. Approximately 21% of these receipts reflect oil and natural gas sales during February 2026 through April 2026, and approximately 79% from prior sales periods including $15.5 million of proceeds from the previously announced settlement and mutual release agreement affecting certain leasehold in Midland County, Texas. The average realized prices for oil and natural gas sales cash receipts attributable to the NPI properties during the second quarter of 2026 were $67.87/bbl and $3.56/mcf, respectively. Liquidity and Capital Resources Capital Resources 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. Contractual Obligations 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 May 2026 for a term of 86 months, beginning March 1, 2029 and expiring April 30, 2036. Under the third and fourth amendments to the Office Lease, monthly rental payments range from $25,000 to $52,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations are summarized in Note 7 to the unaudited condensed consolidated financial statements included in “Item 1 – Financial Statements” of this Quarterly Report. We are not directly liable for the payment of any exploration, development or production costs. We do not have any transactions, arrangements or other relationships that could materially affect our liquidity or the availability of capital resources. We have not guaranteed the debt of any other party, nor do we have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt. To the extent necessary to avoid unrelated business taxable income, our partnership agreement prohibits us from incurring indebtedness, excluding trade payables, in excess of $50,000 in the aggregate at any given time or which would constitute “acquisition indebtedness” (as defined in Section 514 of the Internal Revenue Code of 1986, as amended). 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 East, 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. 11 Table of Contents Liquidity and Working Capital Cash and cash equivalents totaled $72.5 million at June 30, 2026 and $41.9 million at December 31, 2025. Critical Accounting Policies and Estimates As of June 30, 2026, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our Annual Report.