Dorchester Minerals, L.P.: Form 10-Q for the period ended Mar 31, 2025

The following discussion contains forward-looking statements. For a description of limitations inherent in forward-looking statements, see page 1 of this Quarterly Report on Form 10-Q.

Objective

This discussion, which presents our results of operations for the three months ended March 31, 2025 and 2024, 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 594 counties and parishes in 28 states.

As of March 31, 2025, 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 March 31, 2025, the NPI was in a surplus position and had outstanding capital commitments, primarily in the Bakken region, equaling cash on hand of $3.0 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, fluctuations in interest rates, global supply chain disruptions 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

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, the U.S. government has announced and rescinded multiple tariffs on several foreign jurisdictions, which has increased uncertainty regarding the ultimate effect of the tariffs on economic conditions. Current 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, 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, and oil supply dynamics, including the evolving OPEC+ production strategy and potential constraints on Iranian, Russian, and Venezuelan oil exports. While recent volatility in commodity prices is not immediately driving changes in North American production activity, 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.

Results of Operations

Acquisitions for Common Units

On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with West Texas Minerals LLC, a Delaware limited liability company, Carrollton Mineral Partners, LP, a Texas limited partnership, Carrollton Mineral Partners Fund II, LP, a Texas limited partnership, Carrollton Mineral Partners III, LP, a Texas limited partnership, Carrollton Mineral Partners III-B, LP, a Texas limited partnership, Carrollton Mineral Partners IV, LP, a Texas limited partnership, CMP Permian, LP, a Texas limited partnership, CMP Glasscock, LP, a Texas limited partnership, and Carrollton Royalty, LP, a Texas limited partnership (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 million is included in the net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the three months ended March 31, 2025.

On September 30, 2024, pursuant to a non-taxable contribution and exchange agreement with an unrelated third party, the Partnership acquired royalty interests totaling approximately 1,204 net royalty acres located in Weld County, Colorado in exchange for 530,000 common units representing limited partnership interests in the Partnership valued at $16.0 million and issued pursuant to the Partnership’s registration statement on Form S-4.

On March 28, 2024, pursuant to a non-taxable contribution and exchange agreement with multiple unrelated third parties, the Partnership acquired mineral interests totaling approximately 1,485 net royalty acres located in two counties in Colorado in exchange for 505,369 common units representing limited partnership interests in the Partnership valued at $17.0 million and issued pursuant to the Partnership’s registration statement on Form S-4. At closing, in addition to conveying mineral interests to the Partnership, the contributors delivered funds to the Partnership in an amount equal to their cash receipts during the period from January 1, 2024 through March 25, 2024 of $4.0 million. The contributed cash of $4.0 million is included in net cash contributed in acquisitions on the condensed consolidated statement of cash flows for the three months ended March 31, 2024.

Three Months Ended March 31, 2025 as compared to Three Months Ended March 31, 2024

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.

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 first quarter of 2024 to the same period of 2025 is primarily a result of higher suspense releases on new wells on legacy acreage, suspense releases on first time payments from properties acquired in the third quarter of 2024, and increased baseline production from legacy wells and wells acquired in the third quarter of 2024 in the Permian Basin and increased baseline production from wells acquired in the first and third quarters of 2024 in the Rockies, partially offset by lower suspense releases on new wells and decreased baseline production in the Bakken region. The increase in natural gas sales volumes attributable to our Royalty Properties from the first quarter of 2024 to the same period of 2025 is primarily a result of higher suspense releases on new wells on legacy acreage, suspense releases on first time payments from properties acquired in the third quarter of 2024, and increased baseline production from legacy wells and wells acquired in the third quarter of 2024 in the Permian Basin and increased baseline production from wells acquired in the first and third quarters of 2024 in the Rockies, partially offset by lower suspense releases on new wells in the Mid-Continent and East Texas.

The decrease in oil sales volumes attributable to our NPI properties from the first quarter of 2024 to the same period of 2025 is primarily a result of decreased baseline production in the Permian Basin and Bakken region and lower suspense releases on new wells in the Bakken region, partially offset by higher suspense releases on new wells in the Permian Basin. The decrease in natural gas sales volumes attributable to our NPI properties from the first quarter of 2024 to the same period of 2025 is primarily a result of decreased baseline production in the Bakken region and decreased Fayetteville Shale production due to higher prior period adjustments, partially offset by increased baseline production in the Permian Basin.

Operating costs, including production taxes, increased 70% from the first quarter of 2024 to the same period of 2025. The increase is primarily a result of higher proportionate production taxes due to higher oil and natural gas sales revenue, higher proportionate post-production costs, such as compression, transportation, processing, and marketing, due to higher oil and natural gas sales volumes, and higher ad valorem taxes attributable to our Royalty Properties.

Depreciation, depletion and amortization increased 142% from the first quarter of 2024 to the same period of 2025. Depletion is the amount of cost basis of oil and natural gas properties at the beginning of a period attributable to the volume of reserves extracted during such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component in the calculation of depletion. 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 32% from the first quarter of 2024 to the same period of 2025. The increase is primarily a result of increased legal and professional service fees, higher regulatory filing fees due to the Partnership’s S-4 registration statement filing in the first quarter of 2025, and higher compensation expenses, including an expanded Operating Partnership equity program designed for employee retention.

Net cash provided by operating activities increased 19% from the first quarter of 2024 to the same period of 2025 primarily due to higher revenue receipts attributable to our Royalty Properties, net of production taxes and operating expenses, partially offset by lower NPI payment receipts and higher general and administrative expenses.

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 first quarter of 2025 totaled $34.2 million. Approximately 68% of these receipts reflect oil sales during December 2024 through February 2025 and natural gas sales during November 2024 through January 2025, and approximately 32% from prior sales periods. The average realized prices for oil and natural gas sales cash receipts attributable to the Royalty Properties during the first quarter of 2025 were $63.00/bbl and $2.19/mcf, respectively.

Cash receipts attributable to the Partnership's NPI during the first quarter of 2025 totaled $4.8 million. Approximately 74% of these receipts reflect oil and natural gas sales during November 2024 through January 2025, and approximately 26% from prior sales periods. The average realized prices for oil and natural gas sales cash receipts attributable to the NPI properties during the first quarter of 2025 were $58.83/bbl and $1.97/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 on Form 10-Q 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 in 2029. Under the third amendment to the Office Lease, monthly rental payments range from $25,000 to $30,000. Future maturities of Office Lease liabilities representing monthly cash rental payment obligations as of March 31, 2025 are summarized as follows:

(In Thousands)

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 despite potential material uncertainties that may impact us as a result of the ongoing global military conflicts, including in Ukraine and the Middle East and current inflation and interest rates. We cannot predict events that may lead to future oil and natural gas price volatility. Our ability to fund future distributions to unitholders may be affected by the prevailing economic conditions in the oil and natural gas market and other financial and business factors, including global military conflicts, including in Ukraine and the Middle East and changes to tariff and import/export regulation by the United States or other countries, which are beyond our control. If market conditions were to change due to declines in oil prices or 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 factors outside of our control, including those related to changes to tariff and import/export regulations by the United States or other countries or ongoing global military conflicts in Ukraine and the Middle East.

Liquidity and Working Capital

Cash and cash equivalents totaled $41.5 million at March 31, 2025 and $42.5 million at December 31, 2024.

Critical Accounting Policies and Estimates

As of March 31, 2025, there have been no significant changes to our critical accounting policies and related estimates previously disclosed in our Annual Report for the year ended December 31, 2024.

There have been no significant changes in our exposure to market risk during the three months ended March 31, 2025. For a discussion of our exposure to market risk, refer to Item 7A of Part II of the Partnership’s Annual Report for the year ended December 31, 2024.

Evaluation of Disclosure Controls and Procedures

As of the end of the period covered by this Quarterly Report, our principal executive officer and principal financial officer carried out an evaluation of the effectiveness of our disclosure controls and procedures. Based on their evaluation, they have concluded that our disclosure controls and procedures were effective.

Changes in Internal Control

There were no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) during the quarter ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

There have been no material changes to the Partnership’s risk factors as disclosed under “Item 1A – Risk Factors” in the Partnership’s Annual Report on Form 10-K for the year ended December 31, 2024.