{"url_path":"/sec/pbt/10-k/2026/item-2","section_key":"item-2","section_title":"Item 2 Properties","topic":"sec","document":{"doc_type":"10-K/A","doc_date":"2026-07-14","source_url":"https://www.sec.gov/Archives/edgar/data/319654/0001193125-26-303155-index.html","accession_number":"0001193125-26-303155","cik":"0000319654","ticker":"PBT","issuer_name":"PERMIAN BASIN ROYALTY TRUST","edgar_url":"https://www.sec.gov/Archives/edgar/data/319654/0001193125-26-303155-index.html","primary_entity_key":"0000319654","primary_entity_name":"PERMIAN BASIN ROYALTY TRUST"},"word_count":10458,"has_tables":true,"body_markdown":"Item 2. Properties\n\nThe Royalties include: (1) a 75% net overriding royalty carved out of Southland Royalty’s fee mineral interests in the Waddell Ranch in Crane County, Texas (the “Waddell Ranch properties”); and (2) a 95% net overriding royalty carved out of Southland Royalty’s major producing royalty interests in Texas (the “Texas Royalty properties”). The interests out of which the Trust’s net overriding royalty interests were carved were in all cases less than 100%. The Trust’s net overriding royalty interests represent burdens against the properties in favor of the Trust without regard to ownership of the properties from which the overriding royalty interests were carved. The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements under which such royalties were created. References below to “net” wells and acres are to the interests of the owner of the Underlying Properties (from which the Royalties were carved) in the “gross” wells and acres.\n\nThe following information under this Item 2 is based upon data and information, including computation statements, furnished to the Trustee by Blackbeard, the operator of the Waddell Ranch properties, and Riverhill Energy, the operator of the Texas Royalty properties.\n\nPRODUCING ACREAGE, WELLS AND DRILLING\n\nWaddell Ranch Properties. The net profits/overriding royalty interest in the Waddell Ranch properties is the largest asset of the Trust. The mineral interests in the Waddell Ranch, from which such net royalty interests are carved, vary from 37.5% (Trust net interest) to 50% (Trust net interest) in 78,715 gross (34,205 net) producing acres as of December 31, 2023, the most recent date for which the Trustee has information. A majority of the proved reserves are attributable to two fields, the Sand Hills and Waddell. There are 12 producing zones in these fields, and horizontal wells have been drilled in 11 of these zones over the past four years.\n\nProved reserves and estimated future net revenues attributable to the properties are included in the reserve reports summarized below. The owner of the Underlying Properties for Waddell Ranch does not own the full working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest holders as well as the owner of the Underlying Properties. In addition, implementation of any development programs will be dependent upon certain factors including, but not limited to, oil and gas prices currently being received and anticipated to be received in the future, along with the development plans of the operators and owners of the Underlying Properties.\n\nDevelopment information for the Waddell Ranch properties such as well completions, workovers, remedial activities, and plugging and abandonment, is not provided by Blackbeard.\n\nBased on the quarterly reports provided by Blackbeard, the total amount of capital expenditures reported for the months of December 2024 through November of 2025 with regard to the Waddell Ranch properties totaled $228.7 million (gross). Capital\n\n10\n\n[Table of Contents](#toc_page)\n\n \n\nexpenditures do not include the cost of remedial and maintenance activities. The amount spent on remedial and maintenance activities was approximately $21 million for the 12 months included in the 2025 quarterly reports.\n\nThe Trustee has been advised that, effective November 1, 2019, BROG sold its interests in the Waddell Ranch properties to Blackbeard. In conjunction with the transfer and assignment of the Waddell Ranch properties, BROG also assigned to Blackbeard all of its rights, title and interest in and to the Net Overriding Royalty Conveyance (Permian Basin Royalty Trust - Waddell Ranch) dated November 1, 1980. BROG handled all operations and accounting on behalf of Blackbeard until March 31, 2020.\n\nTexas Royalty Properties. The Texas Royalty properties consist of royalty interests in mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others located in 33 counties across Texas. The Texas Royalty properties consist of approximately 125 separate royalty interests containing approximately 303,000 gross (approximately 51,000 net) producing acres. Approximately 35% of the future net revenues discounted at 10% attributable to Texas Royalty properties are located in the Wasson and Yates fields. Detailed information concerning the number of wells on royalty properties is not generally available to the owners of royalty interests. Consequently, an accurate count of the number of wells located on the Texas Royalty properties cannot readily be obtained.\n\nIn February 1997, BROG sold its interests in the Texas Royalty properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (“Texas Royalty Conveyance”) to Riverhill Energy Corporation (“Riverhill Energy”), which was then a wholly-owned subsidiary of Riverhill Capital and an affiliate of Coastal Management Corporation (“CMC”). The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the requirements upon, and the responsibilities of BROG under, the Texas Royalty Conveyance with regard to the Texas Royalty properties. BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty properties were being performed by Riverhill Energy.\n\nThe Trustee has been advised that, effective April 1, 1998, Schlumberger Technology Corporation (“STC”) acquired all of the shares of stock of Riverhill Capital. Prior to the acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital. The Trustee has further been advised, in accordance with the STC acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy.\n\nEffective January 1, 2001 CMC merged into STC. Thus, the ownership in the Texas Royalty properties remained in Riverhill Energy.\n\nThe Trustee has been advised that as of May 1, 2000, the accounting operations pertaining to the Texas Royalty properties were transferred from STC to Riverhill Energy.\n\nWell Count and Acreage Summary. Information regarding the gross and net producing oil and gas wells and acres for the Blackbeard interests on the Waddell Ranch and Riverhill Energy’s interest in the Texas Royalty properties as of December 31, 2025 is not available.\n\nOIL AND GAS PRODUCTION\n\nThe Trust recognizes production during the month in which the related distribution is received. As of May 2024, Blackbeard no longer provides the Trustee information necessary to calculate the net proceeds as of the NYSE notification date for the monthly distribution, such that oil and gas production for the calendar year 2024 is associated with actual production for 11 months from November 2023 through September 2024 and oil and gas production for the calendar year 2025 is associated with actual production for the 12 months of October 2024 through September 2025. Production for the Texas Royalty Properties is for the 12 months from November of the prior year through October of the current year for both 2024 and 2025. Production of oil and gas attributable to the Royalties and the Underlying Properties, the related average sales prices and the average production cost per unit of production\n\n11\n\n[Table of Contents](#toc_page)\n\n \n\nattributable to the Underlying Properties for the three years ended December 31, 2025, excluding portions attributable to the adjustments discussed above, were as follows:\n\n \n\n \n\nWaddell Ranch Properties\n\n \n\n \n\nTexas Royalty Properties\n\n \n\n \n\nTotal\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\nRoyalties:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProduction\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOil (barrels)\n\n \n\n \n\n3,264,554\n\n \n\n \n\n \n\n2,030,905\n\n \n\n \n\n \n\n2,086,029\n\n \n\n \n\n \n\n168,096\n\n \n\n \n\n \n\n183,208\n\n \n\n \n\n \n\n191,278\n\n \n\n \n\n \n\n3,432,650\n\n \n\n \n\n \n\n2,214,113\n\n \n\n \n\n \n\n2,277,307\n\n \n\nGas (Mcf)\n\n \n\n \n\n15,425,945\n\n \n\n \n\n \n\n12,120,840\n\n \n\n \n\n \n\n11,949,062\n\n \n\n \n\n \n\n114,853\n\n \n\n \n\n \n\n80,152\n\n \n\n \n\n \n\n225,634\n\n \n\n \n\n \n\n15,540,798\n\n \n\n \n\n \n\n12,200,992\n\n \n\n \n\n \n\n12,174,696\n\n \n\nUnderlying Properties:\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nProduction\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOil (barrels)\n\n \n\n \n\n4,352,738\n\n \n\n \n\n \n\n2,707,874\n\n \n\n \n\n \n\n2,781,372\n\n \n\n \n\n \n\n190,875\n\n \n\n \n\n \n\n205,201\n\n \n\n \n\n \n\n213,525\n\n \n\n \n\n \n\n4,543,613\n\n \n\n \n\n \n\n2,913,075\n\n \n\n \n\n \n\n2,994,897\n\n \n\nGas (Mcf)\n\n \n\n \n\n20,567,926\n\n \n\n \n\n \n\n16,161,120\n\n \n\n \n\n \n\n15,932,082\n\n \n\n \n\n \n\n130,420\n\n \n\n \n\n \n\n89,765\n\n \n\n \n\n \n\n251,846\n\n \n\n \n\n \n\n20,698,346\n\n \n\n \n\n \n\n16,250,885\n\n \n\n \n\n \n\n16,183,928\n\n \n\nAverage Sales Price\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nOil/barrel\n\n \n\n$\n\n65.92\n\n \n\n \n\n$\n\n76.00\n\n \n\n \n\n$\n\n76.71\n\n \n\n \n\n$\n\n66.50\n\n \n\n \n\n$\n\n76.66\n\n \n\n \n\n$\n\n76.91\n\n \n\n \n\n$\n\n65.95\n\n \n\n \n\n$\n\n76.04\n\n \n\n \n\n$\n\n76.72\n\n \n\nGas/Mcf\n\n \n\n$\n\n1.74\n\n \n\n \n\n$\n\n1.40\n\n \n\n \n\n$\n\n2.37\n\n \n\n \n\n$\n\n8.77\n\n \n\n \n\n$\n\n9.94\n\n \n\n \n\n$\n\n4.60\n\n \n\n \n\n$\n\n1.78\n\n \n\n \n\n$\n\n1.45\n\n \n\n \n\n$\n\n2.40\n\n \n\nAverage Production Cost Oil/Gas BOE\n\n \n\n$\n\n18.54\n\n \n\n \n\n$\n\n21.39\n\n \n\n \n\n$\n\n20.59\n\n \n\n \n\n$\n\n7.87\n\n \n\n \n\n$\n\n7.90\n\n \n\n \n\n$\n\n6.95\n\n \n\n \n\n$\n\n18.26\n\n \n\n \n\n$\n\n20.86\n\n \n\n \n\n$\n\n19.98\n\n \n\n \n\nSince the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.\n\nWaddell Ranch properties lease operating expense increased to $98 million (gross) in 2025 from $82 million (gross) for 2024. Lease operating expenses for 2023 were $80 million. A reason for the increase was not provided by Blackbeard. Waddell Ranch lifting cost on a barrel of oil equivalent (“BOE”) basis in 2025 was $18.54 per barrel (“bbl”) as compared to $21.39 per bbl in 2024 and $20.59 in 2023. Gas volumes, reported in thousand cubic feet (“Mcf”), are converted to equivalent BOE at a ratio of six Mcf of gas to one bbl of oil.\n\nPRICING INFORMATION\n\nReference is made to the caption entitled “Regulation” for information as to federal regulation of prices of natural gas. The following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill Energy is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.\n\nOil. The Trustee has previously been advised by the operator that the majority of oil from the Waddell Ranch was pipeline connected and sold under long term crude purchase agreements. Blackbeard did not confirm whether this continues to be the case as of December 31, 2025.\n\nGas. The trustee has previously been advised by the operator that the majority of gas produced from Waddell Ranch properties was processed through Targa Resources Corporation Midway processing plant. Both residue gas and plant products were purchased by Targa who received fees (gathering, compression, treating, processing) and a percentage of the gas and liquids as compensation. Blackbeard did not confirm whether this continues to be the case as of December 31, 2025.\n\nOIL AND GAS RESERVES\n\nThe following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Item:\n\n“Proved oil and gas reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.\n\n(i)\nThe area of the reservoir considered as proved includes:\n\n(A)\nThe area identified by drilling and limited by fluid contacts, if any, and\n\n(B)\nAdjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.\n\n12\n\n[Table of Contents](#toc_page)\n\n \n\n(ii)\nIn the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (“LKH”) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.\n\n(iii)\nWhere direct observation from well penetrations has defined a highest known oil (“HKO”) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.\n\n(iv)\nReserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:\n\n(A)\nSuccessful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and\n\n(B)\nThe project has been approved for development by all necessary parties and entities, including governmental entities.\n\n(v)\nExisting economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.\n\n“Developed oil and gas reserves” are reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.\n\n“Estimated future net revenues” are computed by applying average prices during the 12-month period prior to fiscal year-end determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. “Estimated future net revenues” are sometimes referred to herein as estimated future net cash flows.\n\n“Present value of estimated future net revenues” is computed using the estimated future net revenues and a discount factor of 10%.\n\n“Reserves” are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.\n\n“Undeveloped oil and gas reserves” are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.\n\n(i)\nReserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.\n\n(ii)\nUndrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.\n\n(iii)\nUnder no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in 17 CFR 210.4-10(a)(2), or by other evidence using reliable technology establishing reasonable certainty.\n\nBlackbeard does not provide a development budget or any forwarding looking information. As a result, in contrast to prior years, the reserve estimates as of December 31, 2024 and December 31, 2025, exclude all proved undeveloped reserves due to lack of a development plan reflecting wells to be drilled. In 2023, the last year for which development plan information was available, the proved undeveloped reserves constituted 48.3% of the total proved reserves for the Waddell Ranch properties and 38% of the total proved reserves for the Trust.\n\n13\n\n[Table of Contents](#toc_page)\n\n \n\nThe process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal policies and controls for estimating reserves, which are reviewed annually and updated as required, and the Trust reviews the reserve reports prepared by Cawley, Gillespie & Associates, Inc. (“CG&A”). As described above, the Trust does not have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers production information (which information is net to the Trust’s interests in the Underlying Properties) and provides such information to CG&A who extrapolates from such information estimates of the reserves attributable to the Underlying Properties based on its expertise in the oil and gas fields where the Underlying Properties are situated, as well as publicly available information. The Trustee does not have an internal petroleum engineer or petroleum engineering department and depends on CG&A to provide information regarding oil and gas reserves. The Trust’s policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance.\n\nThe independent petroleum engineers’ reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were prepared by CG&A, whose firm registration number is F-693, was founded in 1961 and is nationally recognized in the evaluation of oil and natural gas properties. The technical person at CG&A primarily responsible for overseeing the reserves estimates with respect to the Trust is Zane Meekins. Mr. Meekins has been a practicing petroleum engineering consultant since 1989 with over 37 years of practice experience in petroleum engineering and is a registered professional engineer in the State of Texas (License No. 71055). Mr. Meekins graduated from Texas A&M University in 1987, Summa Cum Laude, with a B.S. degree in Petroleum Engineering. Both CG&A and Mr. Meekins have indicated that they meet or exceed all requirements set forth in Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers.\n\nCawley, Gillespie & Associates, Inc.’s reports are attached as exhibits to this Form 10-K. The following table presents a reconciliation of proved reserve quantities from December 31, 2022 through December 31, 2025 (in thousands):\n\n \n\n \n\nWaddell Ranch Properties\n\n \n\n \n\nTexas Royalty Properties\n\n \n\n \n\nTotal\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\nDecember 31, 2022\n\n \n\n \n\n8,893\n\n \n\n \n\n \n\n24,417\n\n \n\n \n\n \n\n2,660\n\n \n\n \n\n \n\n1,321\n\n \n\n \n\n \n\n11,553\n\n \n\n \n\n \n\n25,737\n\n \n\n \n\n \n\n15,843\n\n \n\nExtensions, discoveries, and other additions\n\n \n\n \n\n4,504\n\n \n\n \n\n \n\n8,064\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n4,504\n\n \n\n \n\n \n\n8,064\n\n \n\n \n\n \n\n5,848\n\n \n\nRevisions of previous estimates\n\n \n\n \n\n(2,137\n\n)\n\n \n\n \n\n5,084\n\n \n\n \n\n \n\n20\n\n \n\n \n\n \n\n2,052\n\n \n\n \n\n \n\n(2,118\n\n)\n\n \n\n \n\n7,137\n\n \n\n \n\n \n\n(929\n\n)\n\nProduction\n\n \n\n \n\n(2,086\n\n)\n\n \n\n \n\n(11,949\n\n)\n\n \n\n \n\n(191\n\n)\n\n \n\n \n\n(226\n\n)\n\n \n\n \n\n(2,277\n\n)\n\n \n\n \n\n(12,175\n\n)\n\n \n\n \n\n(4,306\n\n)\n\nDecember 31, 2023\n\n \n\n \n\n9,174\n\n \n\n \n\n \n\n25,616\n\n \n\n \n\n \n\n2,489\n\n \n\n \n\n \n\n3,147\n\n \n\n \n\n \n\n11,662\n\n \n\n \n\n \n\n28,763\n\n \n\n \n\n \n\n16,456\n\n \n\nExtensions, discoveries, and other additions\n\n \n\n \n\n2,213\n\n \n\n \n\n \n\n6,195\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n2,213\n\n \n\n \n\n \n\n6,195\n\n \n\n \n\n \n\n3,245\n\n \n\nRevisions of previous estimates\n\n \n\n \n\n(3,449\n\n)\n\n \n\n \n\n2,311\n\n \n\n \n\n \n\n154\n\n \n\n \n\n \n\n(1,852\n\n)\n\n \n\n \n\n(3,293\n\n)\n\n \n\n \n\n460\n\n \n\n \n\n \n\n(3,216\n\n)\n\nProduction\n\n \n\n \n\n(2,031\n\n)\n\n \n\n \n\n(12,121\n\n)\n\n \n\n \n\n(183\n\n)\n\n \n\n \n\n(80\n\n)\n\n \n\n \n\n(2,214\n\n)\n\n \n\n \n\n(12,201\n\n)\n\n \n\n \n\n(4,248\n\n)\n\nDecember 31, 2024\n\n \n\n \n\n5,907\n\n \n\n \n\n \n\n22,001\n\n \n\n \n\n \n\n2,460\n\n \n\n \n\n \n\n1,215\n\n \n\n \n\n \n\n8,368\n\n \n\n \n\n \n\n23,217\n\n \n\n \n\n \n\n12,237\n\n \n\nExtensions, discoveries, and other additions\n\n \n\n \n\n4,886\n\n \n\n \n\n \n\n12,148\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n4,886\n\n \n\n \n\n \n\n12,148\n\n \n\n \n\n \n\n6,911\n\n \n\nRevisions of previous estimates\n\n \n\n \n\n3,405\n\n \n\n \n\n \n\n17,631\n\n \n\n \n\n \n\n159\n\n \n\n \n\n \n\n250\n\n \n\n \n\n \n\n3,563\n\n \n\n \n\n \n\n17,881\n\n \n\n \n\n \n\n6,543\n\n \n\nProduction\n\n \n\n \n\n(3,265\n\n)\n\n \n\n \n\n(15,426\n\n)\n\n \n\n \n\n(168\n\n)\n\n \n\n \n\n(115\n\n)\n\n \n\n \n\n(3,433\n\n)\n\n \n\n \n\n(15,541\n\n)\n\n \n\n \n\n(6,023\n\n)\n\nDecember 31, 2025\n\n \n\n \n\n10,933\n\n \n\n \n\n \n\n36,354\n\n \n\n \n\n \n\n2,451\n\n \n\n \n\n \n\n1,350\n\n \n\n \n\n \n\n13,384\n\n \n\n \n\n \n\n37,705\n\n \n\n \n\n \n\n19,668\n\n \n\n \n\nRevisions to proved reserve volumes in each year were primarily attributable to changes in commodity prices and variations in the performance of the underlying net profits interests relative to the prior year reserve report. The performance-related revisions reflect several factors, including the level of development activity, production volumes, and development costs associated with the net profits interests.\n\n•\nFor the year ended December 31, 2025, revisions increased proved reserves primarily as a result of improved performance of the net profits interests, associated with significant development activity at the Waddell Ranch, which increased reserve volumes by 7,582 thousand barrels of oil equivalent (\"MBOE\"). This favorable impact was partially offset by lower commodity prices, which reduced reserve volumes by 1,039 MBOE.\n\n•\nFor the year ended December 31, 2024, proved reserve quantities were revised downward primarily due to lower performance of the net profits interests, resulting in a decrease of 3,104 MBOE, together with the effect of lower commodity prices, which reduced reserve volumes by 112 MBOE.\n\n•\nFor the year ended December 31, 2023, revisions to proved reserve quantities were primarily attributable to lower commodity prices, which reduced reserve volumes by 4,904 MBOE. This decrease was partially offset by improved performance of the net profits interests, which increased reserve volumes by 3,975 MBOE.\n\n \n\n14\n\n[Table of Contents](#toc_page)\n\n \n\n \n\nEstimated quantities of proved reserves and net cash flow as of December 31, 2025 are as follows (in thousands):\n\n \n\n \n\nWaddell Ranch Properties\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\n \n\nNet Cash\nFlow, $\n\n \n\n \n\n10% Disc.\nCash\nFlow, $\n\n \n\nProved Developed Producing\n\n \n\n \n\n10,933\n\n \n\n \n\n \n\n36,354\n\n \n\n \n\n \n\n16,992\n\n \n\n \n\n$\n\n766,496\n\n \n\n \n\n$\n\n481,716\n\n \n\nProved Developed\n\n \n\n \n\n10,933\n\n \n\n \n\n \n\n36,354\n\n \n\n \n\n \n\n16,992\n\n \n\n \n\n$\n\n766,496\n\n \n\n \n\n$\n\n481,716\n\n \n\nTotal Proved\n\n \n\n \n\n10,933\n\n \n\n \n\n \n\n36,354\n\n \n\n \n\n \n\n16,992\n\n \n\n \n\n$\n\n766,496\n\n \n\n \n\n$\n\n481,716\n\n \n\n \n\n \n\n \n\nTexas Royalty Properties\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\n \n\nNet Cash\nFlow, $\n\n \n\n \n\n10% Disc.\nCash\nFlow, $\n\n \n\nProved Developed Producing\n\n \n\n \n\n2,451\n\n \n\n \n\n \n\n1,350\n\n \n\n \n\n \n\n2,676\n\n \n\n \n\n$\n\n159,226\n\n \n\n \n\n$\n\n66,206\n\n \n\nProved Developed\n\n \n\n \n\n2,451\n\n \n\n \n\n \n\n1,350\n\n \n\n \n\n \n\n2,676\n\n \n\n \n\n$\n\n159,226\n\n \n\n \n\n$\n\n66,206\n\n \n\nTotal Proved\n\n \n\n \n\n2,451\n\n \n\n \n\n \n\n1,350\n\n \n\n \n\n \n\n2,676\n\n \n\n \n\n$\n\n159,226\n\n \n\n \n\n$\n\n66,206\n\n \n\n \n\n \n\nTotal Waddell Ranch Plus Texas Royalty\nProperties\n\n \n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\n \n\nNet Cash\nFlow, $\n\n \n\n \n\n10% Disc.\nCash\nFlow, $\n\n \n\nProved Developed Producing\n\n \n\n \n\n13,384\n\n \n\n \n\n \n\n37,705\n\n \n\n \n\n \n\n19,668\n\n \n\n \n\n$\n\n925,721\n\n \n\n \n\n$\n\n547,922\n\n \n\nProved Developed\n\n \n\n \n\n13,384\n\n \n\n \n\n \n\n37,705\n\n \n\n \n\n \n\n19,668\n\n \n\n \n\n$\n\n925,721\n\n \n\n \n\n$\n\n547,922\n\n \n\nTotal Proved\n\n \n\n \n\n13,384\n\n \n\n \n\n \n\n37,705\n\n \n\n \n\n \n\n19,668\n\n \n\n \n\n$\n\n925,721\n\n \n\n \n\n$\n\n547,922\n\n \n\nEstimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in thousands):\n\n \n\nProved Developed Reserves:\n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\nDecember 31, 2022\n\n \n\n \n\n8,022\n\n \n\n \n\n \n\n21,216\n\n \n\n \n\n \n\n11,558\n\n \n\nDecember 31, 2023\n\n \n\n \n\n7,236\n\n \n\n \n\n \n\n21,001\n\n \n\n \n\n \n\n10,736\n\n \n\nDecember 31, 2024\n\n \n\n \n\n8,368\n\n \n\n \n\n \n\n23,217\n\n \n\n \n\n \n\n12,237\n\n \n\nDecember 31, 2025\n\n \n\n \n\n13,384\n\n \n\n \n\n \n\n37,705\n\n \n\n \n\n \n\n19,668\n\n \n\n \n\nEstimated quantities of proved undeveloped reserves of oil and gas as of the dates indicated were as follows (in thousands):\n\n \n\nProved Undeveloped Reserves:\n\n \n\nOil\n(Bbls)\n\n \n\n \n\nGas\n(Mcf)\n\n \n\n \n\nBOE\n\n \n\nDecember 31, 2022\n\n \n\n \n\n3,531\n\n \n\n \n\n \n\n4,521\n\n \n\n \n\n \n\n4,284\n\n \n\nDecember 31, 2023\n\n \n\n \n\n4,427\n\n \n\n \n\n \n\n7,762\n\n \n\n \n\n \n\n5,720\n\n \n\nDecember 31, 2024\n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\nDecember 31, 2025\n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\nThe SEC requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves.\n\nEstimates of proved oil and gas reserves are by their very nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables.\n\n15\n\n[Table of Contents](#toc_page)\n\n \n\nThe 2025, 2024 and 2023 change in the standardized measure of discounted future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):\n\n \n\n \n\nWaddell Ranch Properties\n\n \n\n \n\nTexas Royalty Properties\n\n \n\n \n\nTotal\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\nJanuary 1\n\n \n\n$\n\n292,782\n\n \n\n \n\n$\n\n426,341\n\n \n\n \n\n$\n\n579,453\n\n \n\n \n\n$\n\n78,584\n\n \n\n \n\n$\n\n82,208\n\n \n\n \n\n$\n\n107,013\n\n \n\n \n\n$\n\n371,366\n\n \n\n \n\n$\n\n508,548\n\n \n\n \n\n$\n\n686,467\n\n \n\nExtensions, discoveries,\n   and other additions\n\n \n\n \n\n220,395\n\n \n\n \n\n \n\n108,923\n\n \n\n \n\n \n\n185,611\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n—\n\n \n\n \n\n \n\n220,395\n\n \n\n \n\n \n\n108,923\n\n \n\n \n\n \n\n185,611\n\n \n\nAccretion of discount\n\n \n\n \n\n29,278\n\n \n\n \n\n \n\n42,634\n\n \n\n \n\n \n\n57,945\n\n \n\n \n\n \n\n7,858\n\n \n\n \n\n \n\n8,221\n\n \n\n \n\n \n\n10,701\n\n \n\n \n\n \n\n37,136\n\n \n\n \n\n \n\n50,855\n\n \n\n \n\n \n\n68,646\n\n \n\nRevisions of previous\n   estimates and other\n\n \n\n \n\n(60,739\n\n)\n\n \n\n \n\n(272,293\n\n)\n\n \n\n \n\n(382,673\n\n)\n\n \n\n \n\n(8,680\n\n)\n\n \n\n \n\n2,295\n\n \n\n \n\n \n\n(20,490\n\n)\n\n \n\n \n\n(69,420\n\n)\n\n \n\n \n\n(269,997\n\n)\n\n \n\n \n\n(403,164\n\n)\n\nRoyalty income\n\n \n\n \n\n—\n\n \n\n \n\n \n\n(12,823\n\n)\n\n \n\n \n\n(13,995\n\n)\n\n \n\n \n\n(11,555\n\n)\n\n \n\n \n\n(14,140\n\n)\n\n \n\n \n\n(15,016\n\n)\n\n \n\n \n\n(11,555\n\n)\n\n \n\n \n\n(26,963\n\n)\n\n \n\n \n\n(29,011\n\n)\n\nDecember 31\n\n \n\n$\n\n481,716\n\n \n\n \n\n$\n\n292,782\n\n \n\n \n\n$\n\n426,341\n\n \n\n \n\n$\n\n66,206\n\n \n\n \n\n$\n\n78,584\n\n \n\n \n\n$\n\n82,208\n\n \n\n \n\n$\n\n547,922\n\n \n\n \n\n$\n\n371,366\n\n \n\n \n\n$\n\n508,549\n\n \n\n \n\nAverage oil and gas prices of $65.34 per barrel and $3.387 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2025. The increase in the discounted future net cash flows for the Waddell Ranch properties was primarily due to new drilling projects. The discounted future net cash flows for the Texas Royalty properties decreased primarily due to lower oil pricing.\n\nAverage oil and gas prices of $75.48 per barrel and $2.13 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2024. The decrease in discounted future net cash flows for the Waddell Ranch properties was primarily due to exclusion of proved undeveloped reserves and weaker pricing for oil and gas. The discounted future net cash flows for the Texas Royalty properties decreased due to weaker pricing for oil.\n\nAverage oil and gas prices of $78.22 per barrel and $2.64 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties at December 31, 2023. The decrease in the discounted future net cash flows for the Waddell Ranch properties was primarily due to weaker pricing for oil and gas. Discounted future net cash flows for the Texas Royalty properties decreased primarily due to weaker pricing for oil.\n\nThe following presents estimated future net revenue and the present value of estimated future net revenue attributable to the Royalties, for each of the years ended December 31, 2025, 2024 and 2023 (in thousands):\n\n \n\n \n\n2025\n\n \n\n \n\n2024\n\n \n\n \n\n2023\n\n \n\n \n\nEstimated\nFuture Net\nRevenue\n\n \n\n \n\nPresent\nValue at\n10%\n\n \n\n \n\nEstimated\nFuture Net\nRevenue\n\n \n\n \n\nPresent\nValue at\n10%\n\n \n\n \n\nEstimated Future\nNet Revenue\n\n \n\n \n\nPresent\nValue at\n10%\n\n \n\nTotal Proved\n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\n \n\nWaddell Ranch properties\n\n \n\n$\n\n766,496\n\n \n\n \n\n$\n\n481,716\n\n \n\n \n\n$\n\n460,094\n\n \n\n \n\n$\n\n292,782\n\n \n\n \n\n$\n\n707,043\n\n \n\n \n\n$\n\n426,341\n\n \n\nTexas Royalty properties\n\n \n\n \n\n159,226\n\n \n\n \n\n \n\n66,206\n\n \n\n \n\n \n\n183,558\n\n \n\n \n\n \n\n78,584\n\n \n\n \n\n \n\n190,372\n\n \n\n \n\n \n\n82,208\n\n \n\nTotal\n\n \n\n$\n\n925,721\n\n \n\n \n\n$\n\n547,922\n\n \n\n \n\n$\n\n643,652\n\n \n\n \n\n$\n\n371,366\n\n \n\n \n\n$\n\n897,415\n\n \n\n \n\n$\n\n508,549\n\n \n\n \n\nReserve quantities and revenues shown in the preceding tables for the Royalties were estimated from projections of reserves and revenue attributable to the combined Blackbeard, Riverhill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties. Reserve quantities attributable to the Royalties were estimated by allocating to the Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalties are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalties. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur.\n\nProved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the original estimate. Moreover, the present values shown above should not be considered as the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would include many additional factors.\n\nDetailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or development wells drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such information.\n\n16\n\n[Table of Contents](#toc_page)\n\n \n\nREGULATION\n\nMany aspects of the exploration and production, pricing, transportation and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.\n\nExploration and production operations are subject to various types of regulation at the federal, tribal, state and local levels. Such regulation includes requiring permits for the drilling and production of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, controlling and remediating pollution from exploration and production activities, proper handling and disposal of waste generated from exploration and production operations, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting and regulate the flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that can be produced, potentially to raise prices, and to limit the number of wells or the locations which can be drilled.\n\nFederal Natural Gas Regulation\n\nThe Federal Energy Regulatory Commission (the “FERC”) is primarily responsible for federal regulation of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal governmental regulation, including regulation of transportation and storage tariffs and various other matters, by the FERC. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or the FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas are not subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.\n\nSales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial decisions and final decisions by the FERC.\n\nNew proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach recently pursued by the FERC and Congress will continue.\n\nSales of crude oil, condensate and natural gas liquids are not currently regulated and are made at market prices. Crude oil prices are affected by a variety of factors. Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the Organization of Petroleum Export Countries (“OPEC”).\n\nOn December 19, 2007, President Bush signed into law the Energy Independence & Security Act of 2007 (PL 110 140)(the “EISA”). The EISA, among other things, prohibits market manipulation by any person in connection with the purchase or sale of crude oil, gasoline or petroleum distillates at wholesale in contravention of such rules and regulations that the Federal Trade Commission may prescribe, directs the Federal Trade Commission to enforce the regulations, and establishes penalties for violations thereunder.\n\nState Regulation\n\nThe various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing, number, operation of wells and the prevention of waste of oil and gas\n\n17\n\n[Table of Contents](#toc_page)\n\n \n\nresources, bonding or other financial assurance to drill or operate wells, decommissioning and removal of equipment, and the plugging and abandonment of wells. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from the wells on the Underlying Properties, negatively affect the economics of production from these wells, or limit the number of wells or locations can be drilled.\n\nLocal Regulation\n\nDrilling for and production and transportation of crude oil and natural gas are also regulated by local authorities. Local laws may include land use regulations, permitting requirements, and noise and traffic ordinances. Such regulation could increase drilling and production costs or create delays in development and production of the Underlying Properties.\n\nEnvironmental Regulation\n\nCompanies in the oil and gas industry are subject to stringent and complex federal, tribal, state and local laws and regulations governing the health and safety aspects of oil and gas operations, the management and discharge of materials into the environment, or otherwise relating to environmental protection. Those laws and regulations may impose numerous obligations that are applicable to the operations of the Underlying Properties, including the acquisition of a permit before conducting drilling, production or underground injection activities; the restriction on the types, quantities and concentrations of materials that can be emitted or released into the environment; the limitation or prohibition of drilling or other construction or operational activities on certain lands lying within wilderness, wetlands, endangered or threatened species habitat, and other sensitive environments or protected areas; the installation of emission monitoring and/or pollution control equipment; the reporting of the types and quantities of various substances that are generated, stored, processed, released, or disposed of in connection with operation of the Underlying Properties; the remediation of pollution from current or former operations, such as cleanup of releases, pit closure, removal of surface equipment and plugging of abandoned wells; the sourcing and disposal of water used in the drilling, fracturing completion and production processes; the planning and preparedness for spill and emergency response activities; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions, water discharges and current and historical waste disposal practices. Failure to comply with these laws and regulations may result in the adverse modification, suspension or revocation of necessary permits, licenses and authorizations; the requirement that additional pollution controls be installed; the assessment of administrative, civil or criminal fines or penalties; the imposition of investigatory, ongoing monitoring, or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations. Under certain environmental laws and regulations, the operators of the Underlying Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released materials or property contamination, in either case, whether at a drilling or other operations site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.\n\nAll of the jurisdictions in which the Underlying Properties are operated have statutory and administrative provisions regulating the exploration for and production of oil and natural gas, including, for example, provisions related to the sourcing and disposal of water used in the drilling and completion process, the control and permitting of air emissions from well completion and production operations, the management and disposal of wastes and wastewater (including produced water) generated from the operation of the Underlying Properties, decommissioning and removal of equipment, bonding to drill or operate wells, decommissioning and removal of equipment, and the plugging and abandonment of wells. Operation of the Underlying Properties is also subject to regulations that generally prohibit the venting or flaring of natural gas. The effect of such regulations may be to limit the amounts of oil and natural gas that may be produced from the wells on the Underlying Properties or negatively affect the economics of production from these wells.\n\nIn addition, climate change is the subject of an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. The United States, depending on which President has been in office, has participated (during the Biden administration) or not (during the two Trump administrations) in the Paris Climate Accord, a voluntary international agreement with the goal of limiting global climate change to not more than 2 degrees Celsius (or less). The Biden administration had also set ambitious domestic targets for curbing climate change, such as making the U.S. power sector carbon-neutral by 2035 and announcing a plan to achieve net-zero emissions from overall federal operations by 2050. While changes in U.S. presidential administrations could increase or lessen the relative impacts of climate policies and regulations on the oil and natural gas industry, the adoption and implementation of any international, federal, or state greenhouse gas (“GHG”)-emission reduction commitments, legislation, or regulations or other restrictions or imposition of taxes, fees, or limits on emissions of GHGs could result in increased development, operation, and compliance costs, additional operating restrictions on the Underlying Properties, and additional regulatory burdens, and thus decrease revenue to the Trust.\n\n18\n\n[Table of Contents](#toc_page)\n\n \n\nIn response to the April 2007 U.S. Supreme Court decision in Massachusetts vs. EPA finding that greenhouse gases (“GHGs”) are air pollutants under the Clean Air Act (“CAA”), the United States Environmental Protection Agency (the “EPA”) issued an “Endangerment Finding” under Section 202(a) of the CAA, concluding that GHG pollution threatens the public health and welfare of future generations. Thereafter, EPA promulgated GHG monitoring and reporting regulations (the “GHG Reporting Rule”) that, since 2011, have required annual reporting of carbon dioxide, methane and nitrous oxide emissions from certain sources in the oil and natural gas industry sector, including in the onshore oil and natural gas production segment. The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG emission limits. In August 2022, Congress passed the Inflation Reduction Act, which included requirements to impose fees beginning in 2025 on 2024 calendar year methane emissions from oil and gas operations that are required to report their GHG emissions under the EPA’s GHG Reporting Rule. EPA’s final rule to implement the fee requirements, “Waste Emissions Charge for Petroleum and Natural Gas Systems” was published on November 18, 2024, and took effect on January 17, 2025. Compliance with these rules would have required enhanced record-keeping practices and, thus, may have increased operating costs associated with the Underlying Properties and may have decreased net revenue to the Trust. However, following the second Trump presidential inauguration, Congress postponed collection of the Waste Emissions Charge until 2034 under the One Big Beautiful Bill Act, which President Trump signed into law on July 4, 2025. And, consistent with that postponement, EPA proposed on September 12, 2025, to suspend all GHG reporting for the oil and gas sector (40 C.F.R. Part 98, Subpart W) until 2034. Further, on February 12, 2026, EPA rescinded the endangerment finding on the basis that EPA lacks statutory authority under Section 202(a) of the CAA to prescribe standards for GHG emissions, thus creating additional uncertainty about the scope and extent of GHG regulation in the United States. If the GHG reporting rule is not permanently repealed and if the rescission of the endangerment finding is not upheld in the litigation that promptly ensued, operating costs associated with GHG recordkeeping and reporting will continue to be incurred for the Royalty Properties. If GHG enhanced reporting, emission fees, reduction targets, or additional permitting are reinstated or imposed in the future, such requirements could decrease net revenue to the Trust.\n\n \n\nIn addition, on May 9, 2024, pursuant to its authority under Section 111 of the CAA to set emission standards for new and existing power plants based on the “best system of emission reduction,” EPA finalized new source performance standards for GHG emissions from fossil fuel-fired stationary combustion turbine electricity generating units and from certain fossil-fuel fired steam generating units. Among other requirements, the rule, effective July 8, 2024, revised CAA New Source Performance Standards (“NSPS”) for new or substantially modified natural gas-fired power plants based on the use of more efficient fuels, simple cycle operation, and the implementation of carbon capture and sequestration/storage technology. The rule also revises the NSPS for GHG emissions from fossil fuel–fired steam generating units that undertake major modifications. The rule was promptly challenged in court, and on June 11, 2025, EPA under the second Trump Administration proposed to repeal GHG emissions standards for fossil fuel-fired power plants and to make a finding that GHG emissions from fossil fuel-fired power plants do not contribute significantly to dangerous air pollution or, in the alternative, repeal certain other requirements, such as the emission guidelines for existing fossil fuel-fired steam generating units, and certain carbon capture and storage standards for coal-fired steam generating units and new base load stationary combustion turbines. Adoption of rules that either place additional limits on GHG emissions from fossil fuel-fired electricity or steam generating units or otherwise incentivize non-fossil fuel generated sources of energy could reduce demand for oil and gas generally, including oil and gas produced from the Royalty Properties and could increase the cost of operations of the Underlying Properties, which could result in a loss of reserves or revenues to the Trust.\n\nPursuant to the CAA and state laws concerning the permitting of air emissions, certain new and modified sources of air emissions are subject to air permitting authorizations for construction and operation, and sources of air emissions at the Underlying Properties are no exception to these requirements. In addition to air permitting requirements, certain sources of emissions involved in oil and gas operations are subject to source-specific emission standards pursuant to CAA New Source Performance Standards (“NSPS”) and National Emissions Standards for Hazardous Air Pollutants (“NESHAPs”). For example, on August 16, 2012, the EPA issued a final rule, known as NSPS Subpart OOOO, that established new source performance standards for volatile organic compounds (“VOCs”) and sulfur dioxide, an air toxics standard for major sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. The rule applied to certain oil and natural gas sources that were constructed, modified, or reconstructed after August 23, 2011, and required that all hydraulically fractured or refractured natural gas wells be completed using reduced emission (“green”) completion technology, which significantly reduces VOC emissions. Limiting emissions of VOCs also has the co-benefit of limiting methane, a GHG. In addition, these regulations also include requirements applicable to storage tanks and other equipment in the affected oil and natural gas industry segments. On June 3, 2016, EPA promulgated NSPS Subpart OOOOa, establishing additional standards for the reduction of methane, VOCs, and other emissions from new and existing sources in the oil and gas sector. Among other requirements, these NSPS Subpart OOOOa rules, extended green completion requirements to new hydraulically fractured or refractured oil wells. Furthermore, in December 2023, EPA announced additional final NSPS OOOO program rules, referred to as Subparts OOOOb and OOOOc, which are expected to have a significant impact on the upstream and midstream oil and gas sectors from an operational cost perspective. The rules formally instate methane emissions limitations from new, modified, and reconstructed sources; and will regulate existing sources for the first time under the NSPS Subpart OOOOc program by requiring states to implement plans that meet or exceed federally established emission reduction guidelines for existing oil and natural gas facilities. Legal challenges, including by states, to the recently finalized NSPS Subparts OOOOb and OOOOc rules have ensued. Further, the EPA under the second\n\n19\n\n[Table of Contents](#toc_page)\n\n \n\nTrump Administration issued a Final Rule on December 3, 2025, extending certain OOOOb and OOOOc compliance deadlines. Thus, although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of the VOC and methane emissions regulations for the oil and gas production, transmission, and storage industry segments are uncertain at this time as a result of recent rulemakings and ongoing and expected legal challenges.\n\nCongress and various states, including Texas, have proposed or adopted legislation regulating or requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in the drilling operation. Texas requires oil and gas operators to disclose the chemicals on the Frac Focus website. Hydraulic fracturing has historically been regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the “SDWA”). The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuels. Under the guidance, EPA defined the term “diesel” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel.\n\nThe Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls on the discharge of pollutants, including produced waters and other oil and natural gas wastes, into waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or the relevant state agency. The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“USACE”). Whether CWA permitting is required depends upon whether and the extent to which “Waters of the United States” (“WOTUS” or \"jurisdictional waters\") may be impacted by the planned activity—for example, construction of drilling pads, access roads, or pipelines. Rulemaking by EPA and the USACE to define WOTUS has been heavily litigated, resulting in the rule taking effect at times in some states but not others and creating definitions that are more inclusive of certain waters effective in some states and those that are less inclusive effective in other states. EPA and USACE’s WOTUS definition rulemaking published in the Federal Register on January 18, 2023 (the January 2023 Rule) incorporated “relatively permanent” and “significant nexus” standards for determining jurisdiction over adjacent wetlands and additional waters, expanding the types of waters that could be considered WOTUS; however, this WOTUS definition was litigated and eventually amended on August 29, 2023, when EPA and USACE issued a final rule to conform the WOTUS definition to the U.S. Supreme Court’s May 25, 2023 decision in Sackett v. Environmental Protection Agency, which invalidated parts of the January 2023 Rule. With the August 2023 rulemaking, EPA and USACE implemented a narrower definition of WOTUS by, for example, removing “interstate wetlands”; redefining “adjacent” to mean “having a continuous surface connection”; and removing the “significant nexus” standard from the provisions regarding tributaries, adjacent wetlands, and intrastate lakes and ponds. EPA’s November 17, 2025, proposed rule aims to further conform the WOTUS definition to the Sackett decision by providing additional definitions for “relatively permanent,” “tributary,” and “continuous surface connection,” as well as by introducing additional exclusions and revisions to others, including exclusions for groundwater (i.e., groundwater would not be considered WOTUS) and prior converted cropland, an attempt to clarify the exclusion for ditches, and a broader exclusion for wastewater treatment systems. Comments on the November 2025 proposal were due by January 5, 2026. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations, such as spill prevention, control, and countermeasure (“SPCC”) planning, may be triggered during development and operation of the Underlying Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of the Underlying Properties.\n\nSPCC regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans. Federal and state regulatory agencies can impose administrative, civil and criminal fines and penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.\n\nThe Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund” law, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a “hazardous substance” into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous substance at a site, or transported or arranged for transport of a hazardous substance to a site for disposal. CERCLA also authorizes the EPA and, in some cases, private parties to take actions in response to threats to the public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action. From time to time, EPA may designate additional materials as hazardous substances under CERCLA, which could result in additional investigation and remediation at current Superfund sites, or reopener of Superfund sites that previously received regulatory closure. For example, EPA issued a final rule that became effective July 8, 2024, designating as \"hazardous substances\" under CERCLA perfluorooctanoic acid (“PFOA”) and perfluorooctanesulfonic acid (“PFOS”), which have been commonly used in a variety of industrial and consumer products. In the course of operations, the working interest owner and/or the operator of the Underlying Properties may have generated and may generate wastes that may fall within CERCLA’s definition of “hazardous substances.” The operator of the Underlying Properties or the working interest owners may be responsible\n\n20\n\n[Table of Contents](#toc_page)\n\n \n\nunder CERCLA for all or part of the costs to clean up sites at which such substances have been disposed. Although the Trust is not the operator of any of the Underlying Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the extent responsibility under CERCLA could be imposed on such parties as “owners.”\n\nThe Underlying Properties have produced oil and/or gas for many years and, in connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under environmental laws. Although the Trust has no knowledge of the procedures followed by the operators of the Underlying Properties in this regard, hydrocarbons or other solid wastes (including hazardous or nonhazardous waste) may have been or may be disposed or released on, under, or from the Underlying Properties by the current or previous operators or may have been disposed offsite of the Underlying Properties. Federal, state and local laws and regulations applicable to oil and gas-related wastes and properties have become increasingly more stringent. The federal Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 (“RCRA”) and analogous state laws regulate the management and disposal of solid waste, including hazardous and nonhazardous waste. Although some wastes associated with the exploration and production of oil and natural gas are currently regulated as nonhazardous waste and are exempted from hazardous waste regulation under RCRA, this exemption is subject to being limited or lost, and the loss of this exemption would result in more stringent regulation of these types of waste. Moreover, these wastes and other wastes may be otherwise regulated by the EPA or state agencies. In addition, in the ordinary course of operation of the Underlying Properties, industrial wastes such as paint wastes and waste solvents may be regulated as hazardous waste under RCRA or considered hazardous substances under CERCLA. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory, ongoing monitoring, or remedial obligations, and/or the issuance of injunctions limiting or preventing some or all of the operations. Under these laws, removal or remediation of current releases of such materials or of previously disposed wastes or property contamination at a drill site or a waste disposal facility could be required by a governmental authority regardless of whether the operators of the Underlying Properties were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time those actions were taken.\n\nThe federal Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program promulgated under the SDWA and analogous state programs regulate the drilling and operation of salt water disposal and injection wells. EPA directly administers the UIC program in some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal and injection wells, and casing integrity monitoring must be conducted periodically to ensure that the disposed waters are not leaking into groundwater. In addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering additional regulations regarding the potential seismic impacts of such disposal methods. 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 Underlying Properties to dispose of produced water and ultimately increase the cost of operation of the Underlying Properties or delay production schedules. For example, in 2014, the Railroad Commission of Texas (“RRC”) published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Furthermore, in response to a number of earthquakes in recent years in the Midland Basin, the RRC announced in September 2021 that it will not issue any new saltwater disposal (“SWD”) well permits in an area known as the Gardendale Seismic Response Area (“SRA”), and will require existing SWD wells in that area to reduce their maximum daily injection rate to 10,000 barrels per day per well. In December 2021, the RRC went on to suspend all well activity in deep formations in the Gardendale SRA, effectively terminating 33 disposal well permits. The RRC has since identified two additional SRAs; (the Northern Culberson-Reeves (“NCR”) SRA and the Stanton SRA), and required operators in the NCR and Stanton SRAs to develop and implement seismic response plans, (which include expanded data collection efforts, contingency responses for future seismicity, and scheduled checkpoint updates with RRC staff). In response to additional earthquakes in the area, the RRC suspended all (totaling 23) deep disposal well permits in the NCR SRA and proposed additional daily injection volume curtailments for the Stanton SRA. Such restrictions and requirements could limit the Underlying Properties’ oil and gas well exploration and production activities or increase the cost of those activities if wastewater disposal options become limited.\n\nIn addition, several cases have in recent years put a spotlight on the issue of whether injection wells may be regulated under the CWA if a direct hydrological connection to a jurisdictional surface water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. EPA has also brought attention to the reach of the CWA’s jurisdiction in such instances by issuing a request for comment in February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,” and whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater. However, in April 2020, the Supreme Court issued a ruling in the case, County of Maui, Hawaii v.\n\n21\n\n[Table of Contents](#toc_page)\n\n \n\nHawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent” of a direct discharge into navigable waters. In November 2023, EPA issued draft guidance outlining the factors that may be considered when evaluating whether discharges through groundwater may be the “functional equivalent” of a direct discharge and subject to regulation under the CWA National Pollutant Discharge Elimination System permitting program and describing the types of information that should be used in the determination. Comments on the draft guidance were due to the agency by December 27, 2023, and to date EPA has not yet finalized the guidance. If in the future CWA permitting is required for saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v. Hawaii Wildlife Fund, the costs of permitting and compliance for injection well operations by the companies that operate the Underlying Properties could increase.\n\nVarious state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the Bald and Golden Eagle Protection Act, the CWA, and CERCLA.\n\nThe United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.\n\nThe operators of the Underlying Properties are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. In addition to the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the Clean Air Act, and similar state statutes may also require disclosure of information about hazardous materials used, produced or otherwise managed during operation of the Underlying Properties. Some of these laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants.\n\nThe Trustee is unable to predict the total impact of the current and potential regulations upon the operators of the Underlying Properties; the effect that noncompliance with existing environmental laws, rules and regulations; compliance with new legislation or regulation, or enforcement policies thereunder; or claims for property or environmental damage, or for personal injury or death, resulting from operations on the Underlying Properties could have on the Trust or Trust distributions. Even if the Trust were not directly liable for costs or expenses related to these matters, it is possible that the operators of the Underlying Properties could face operational delays, increases in the operating costs to comply with climate change or any other existing or new environmental legislation or regulation, decreases in the completion of new oil and natural gas wells, or an enforcement action or a private party action that could result in wells being plugged and abandoned earlier in their productive lives, resulting in a loss of reserves and revenues to the Trust each of which could reduce net proceeds payable to the Trust and Trust distributions.\n\nOther Regulation\n\nThe petroleum industry is also subject to compliance with various other federal, tribal, state, and local regulations and laws, including, but not limited to, occupational safety, resource conservation and equal employment opportunity. The Trustee does not believe that compliance with these laws by the operating parties will have any material adverse effect on Unit holders."}