Black Stone Minerals, L.P.

General

Black Stone Minerals, L.P. (“BSM,” the “Partnership,” “we” or “us”) is one of the largest owners and managers of oil and natural gas mineral interests in the United States ("U.S."). Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

We own mineral interests in approximately 16.9 million gross acres, with an average 43.4% ownership interest in that acreage. We also own nonparticipating royalty interests in 1.8 million gross acres and overriding royalty interests in 1.6 million gross acres. These non-cost-bearing interests, which we refer to collectively as our “mineral and royalty interests,” include ownership in approximately 71,000 producing wells. Our mineral and royalty interests are located in 41 states in the continental U.S., including all of the major onshore producing basins. Many of these interests are in active resource plays, including the Haynesville/Bossier shales in East Texas/Western Louisiana, the Wolfcamp/Spraberry/Bone Springs in the Permian Basin, the Bakken/Three Forks in the Williston Basin, and the Eagle Ford shale in South Texas. The combination of the breadth of our asset base, the long-lived, non-cost-bearing nature of our mineral and royalty interests, and our active management expose us to potential additional production and reserves from new and existing plays without being required to invest additional capital.

We are a publicly traded Delaware limited partnership formed on September 16, 2014. Our common units trade on the New York Stock Exchange under the symbol "BSM."

BSM files or furnishes annual reports on Form 10-K, quarterly reports on Form 10-Q, and current reports on Form 8-K, as well as any amendments to these reports with the U.S. Securities and Exchange Commission (“SEC”). Through our website, http://www.blackstoneminerals.com, we make available electronic copies of the documents we file or furnish to the SEC. Access to these electronic filings is available free of charge as soon as reasonably practicable after filing or furnishing them to the SEC.

Our Assets

As of December 31, 2025, our total estimated proved oil and natural gas reserves were 54,845 MBoe based on a reserve report prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), an independent third-party petroleum engineering firm. Of our total reserves as of December 31, 2025, approxima tely 88% were proved developed reserves and approxima tely 12% were proved undeveloped reserves. At December 31, 2025, our estimated proved reserves were 30% oil and 70% natural gas.

The locations of our oil and natural gas properties are presented on the following map. Additional information related to these properties is provided below under "Our Properties" by major geographical region and by material resource play, as denoted on the map below.

Mineral and Royalty Interests

Mineral interests are real-property interests that are typically perpetual and grant ownership of the oil and natural gas under a tract of land and the rights to explore for, develop, and produce oil and natural gas on that land or to lease those exploration and development rights to a third party. When those rights are leased, usually for a three-year term, we typically receive an upfront cash payment, known as lease bonus, and we retain a royalty interest, which entitles us to a cost-free percentage (usually ranging from 20% to 25%) of production or revenue from production. A lessee can extend the lease beyond the initial lease term with continuous drilling, production, or other operating activities or by making an extension payment. When drilling and production ceases, the lease terminates, allowing us to lease the exploration and development rights to another party. Mineral interests generate the substantial majority of our revenue and are also the assets over which we have the most influence.

In addition to mineral interests, we also own other types of non-cost-bearing royalty interests, which include:

•Nonparticipating royalty interests (“NPRIs”), which are royalty interests that are carved out of the mineral estate and represent the right, which is typically perpetual, to receive a fixed, cost-free percentage of production or revenue from production, without an associated right to lease or receive lease bonus; and

•Overriding royalty interests (“ORRIs”), which are royalty interests that burden working interests and represent the right to receive a fixed, cost-free percentage of production or revenue from production from a lease. ORRIs remain in effect until the associated leases expire.

We may own more than one type of mineral and royalty interest in the same tract of land. For example, where we own an ORRI in a lease on the same tract of land in which we own a mineral interest, our ORRI in that tract will relate to the same gross acres as our mineral interest in that tract. As of December 31, 2025, approximately 26% of our mineral and royalty interests are leased, calculated on a cumulative gross acreage basis for all three types of mineral and royalty interests.

The majority of our producing mineral and royalty interest acreage is pooled with third-party acreage to form pooled units. Pooling proportionately reduces our royalty interest in wells drilled in a pooled unit, and it proportionately increases the number of wells in which we have such reduced royalty interest.

Non-Operated Working Interests

We own non-operated working interests related to our mineral interests in various plays across our asset base. The majority of our working interest exposure is in the Haynesville/Bossier play in San Augustine County, Texas and Angelina County, Texas. We have farmout arrangements in place for our entire working interest position in that area. We also hold working interests acquired through working interest participation rights, which we often include in the terms of our leases. This participation right complements our core mineral and royalty interest business because it allows us to realize additional value from our minerals. Under the terms of the relevant leases, we are typically granted a unit-by-unit or a well-by-well option to participate on a non-operated working interest basis in drilling opportunities on our mineral acreage. This right to participate in a unit or well is exercisable at our sole discretion. We exercise this option when the results from prior drilling and production activities have substantially reduced the economic risk associated with development drilling and where we believe the probability of achieving attractive economic returns is high. We generally farmout or sell these participation rights to third parties and often retain some form of non-cost-bearing interest in those wells, such as an overriding royalty interest.

When we participate in non-operated working interest opportunities, we are required to pay our portion of the costs associated with drilling and operating these wells. Working interest production represented 4% of our total production volumes during the year ended December 31, 2025. As of December 31, 2025, we owned non-operated working interests in 3,173 gross (178 net) wells.

Acreage Overlap

We present tables in the following sections with information about our mineral and royalty interests and working interests. Some of these tables include acreage by interest type. We may own more than one type of interest in the same tract of land. For example, where we have acquired non-operated working interests related to our mineral interests in a given tract, our working interest acreage in that tract will relate to the same acres as our mineral interest acreage in that tract. Consequently, when acreage is presented by interest type, some of the acreage shown for one type of interest may also be included in the acreage shown for another type of interest. Because of our non-operated working interests, overlap between working interest acreage and mineral and royalty interest acreage can be significant; overlap between the different types of mineral and royalty interests is not significant.

Shelby Trough Development Agreements

We are party to a series of Joint Exploration Agreements ("JEAs"; each, a "JEA") with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage and reduced royalty rates in exchange for meeting minimum annual drilling commitments, as defined by either a minimum number of wells or minimum aggregate lateral feet drilled. Each JEA also includes a banking provision that allows operators that exceed their annual drilling commitments to carry forward excess drilling activity, measured by wells drilled or aggregate lateral feet, to satisfy future obligations, subject to defined caps. The agreements also allow operators to temporarily suspend drilling obligations if natural gas prices fall below certain thresholds. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs.

For additional information about our development activities in the Shelby Trough, please read Part II, Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments”.

Aethon Joint Exploration Agreements

We have two JEAs with Aethon Energy ("Aethon") covering a portion of our acreage in San Augustine County and Angelina County in East Texas. In May 2025, the parties entered into a letter agreement amending the JEAs. As amended, the agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas.

Aethon expects to drill a total of 14 wells in the current program year, ending June 30, 2026, and apply 2 of its banked wells toward its commitment. As of December 31, 2025, Aethon had spud 6 wells in the current program year and had an inventory of 5 wells drilled in the previous program year that are expected to be turned to sales in early 2026. As of December 31, 2025, Aethon had a total of 10 banked wells.

Revenant Joint Exploration Agreement

In May 2025, we entered into a JEA with Revenant Energy (“Revenant”) covering an expanded portion of our Shelby Trough acreage, primarily located in Angelina, Nacogdoches, and San Augustine counties in Texas. The agreement grants Revenant exclusive development rights across three designated areas of interest ("AOIs") and requires minimum annual drilling commitments that escalate over a five-year period, including test wells in certain areas, to maintain development rights across the full contract area. The agreement allows for non-operated working interest participation.

In November 2025, we entered into an amendment to the JEA that maintained the original 6-well commitment for Program Year 1 while revising the structure for subsequent years. After Program Year 1, well count commitments convert to completed gross lateral-foot commitments at a ratio of one well per 7,000 lateral feet, allowing Revenant to drill longer laterals while maintaining overall commitment levels.

The table below summarizes the minimum gross lateral-foot drilling commitments under the agreement, including both AOI-specific and contract-wide commitments, following Program Year 1:

Revenant expects to spud more wells than its 6-well commitment for the first program year, ending December 31, 2026.

Caturus Joint Exploration Agreement

In November 2025, we entered into a JEA with Caturus Energy, LLC (“Caturus”) covering an expanded portion of our Shelby Trough acreage, primarily in Angelina, Cherokee, Houston, and Nacogdoches counties in Texas. The agreement grants Caturus exclusive development rights across the contract area and requires minimum annual drilling commitments to maintain such rights. These commitments are measured in completed lateral feet on a net basis attributable to our mineral ownership interest and include pilot and test wells in the initial program years. The minimum net lateral-foot commitments escalate over a six-year period.

The table below summarizes the minimum net lateral-foot drilling commitments under the agreement:

Farmout Agreements

We previously entered into farmout arrangements covering all our non-operated working interests under our JEAs with Aethon in San Augustine and Angelina Counties. In May 2025, the farmout agreements covering the interests under the JEAs with Aethon terminated, and Aethon assumed the associated working interests as part of an amendment to our JEAs with Aethon. In June 2025, we entered into a farmout arrangement covering all our non-operated working interests under our JEA with Revenant in Angelina, Nacogdoches, and San Augustine Counties, farming out our undivided 35% non-operated working interest to an external capital provider.

Our Properties

BSM Land Regions

We divide the contiguous U.S. into major geographical regions that we refer to as "BSM Land Regions." The following provides an overview of these regions:

•Gulf Coast. The Gulf Coast region consists of the land area along the Gulf of Mexico from South Texas through Florida. This region includes the Western Gulf (onshore), East Texas Basin, Louisiana-Mississippi Salt Basin, and South Florida Basin.

•Southwestern U.S. The Southwestern U.S. region consists of the land area north of the Mexico-United States border from Central Texas westward through Arizona. This region includes the Permian Basin, Fort Worth Basin, Bend Arch, Palo Duro Basin, Dalhart Basin, and Marfa Basin.

•Rocky Mountains. The Rocky Mountains region consists of the land area along the Rocky Mountains from Northern New Mexico through Montana and North Dakota. This region includes the Williston Basin, Montana Thrust Belt, Bighorn Basin, Powder River Basin, Greater Green River Basin, Denver-Julesburg Basin, Uinta-Piceance Basin, Park Basin, Paradox Basin, San Juan Basin, and Raton Basin.

•Eastern U.S. The Eastern U.S. region consists of the land area east of the Mississippi River and north of the Gulf Coast region. This region includes the Michigan Basin, Illinois Basin, Appalachian Basin, and Black Warrior Basin.

•Mid-Continent. The Mid-Continent region extends from Oklahoma north through Minnesota. This region includes the Anadarko Basin, Arkoma Basin, Forest City Basin, Cherokee Platform, Marietta Basin, and Ardmore Basin.

•Western U.S. The Western U.S. region consists of the land area west of the Rocky Mountains and Southwestern U.S. regions. This region includes the San Joaquin Basin, Santa Maria Basin, Ventura Basin, Los Angeles Basin, Sacramento Basin, and Eastern Great Basin.

1 Excludes acreage for which we have incomplete seller records.

2 Refers to our average ownership interest. Ownership interest is the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the BSM Land Region. Our weighted average royalty interest for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average net royalty interest for our mineral interests.

3 Refers to our average royalty interest. Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the BSM Land Region. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.

1 We own both mineral and royalty interests and working interests in 1,991 of the wells shown in each column above.

2 Refers to mineral and royalty interest wells.

Material Resource Plays

The following listing provides an overview of the resource plays we consider most material to our current and future business. These plays accounted for 73% of our aggregate production for the year ended December 31, 2025.

•Bakken/Three Forks. The Bakken shale and underlying Three Forks formation are located in the Williston Basin, which covers parts of North Dakota, South Dakota, and Montana in the U.S., and Saskatchewan and Manitoba in Canada. The U.S. portion of the Bakken/Three Forks play is within the Rocky Mountains BSM Land Region. We have significant exposure in these plays through our mineral and royalty interests as well as through our working interests.

•Haynesville/Bossier. The Haynesville/Bossier formation, located in East Texas and Western Louisiana, is within the Gulf Coast BSM Land Region and is one of the largest producing natural gas formations in the U.S. The play’s prospective acreage is evenly divided between East Texas and Western Louisiana, and while we have significant exposure through our mineral and royalty interests and working interests across the entire play, the majority of our acreage is located in East Texas, with a particular concentration in the prolific southern portion of the Shelby Trough in San Augustine, Nacogdoches, and Angelina Counties.

•Permian-Midland. The Midland Basin, which is a sub-basin within the Permian Basin, is located in West Texas in the Southwestern U.S. BSM Land Region. It is separated from the Delaware Basin to the west by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource plays within the Midland Basin as the Permian-Midland. These plays include the various members of the Spraberry and Wolfcamp formations. Our interests in the Permian-Midland resource plays are almost exclusively mineral and royalty interests.

•Permian-Delaware. The Delaware Basin, which is a sub-basin within the Permian Basin, is located in West Texas and Southeastern New Mexico in the Southwestern U.S. BSM Land Region. It is separated from the Midland Basin to the east by a carbonate platform called the Central Basin Platform. We refer to the various Permian-aged resource plays within the Delaware Basin as the Permian-Delaware. These plays include the various members of the Bone Springs, Avalon, and Wolfcamp formations. Our interests in the Permian-Delaware resource plays are almost exclusively mineral and royalty interests.

•Eagle Ford. The Eagle Ford shale is located in South Texas within the Gulf Coast BSM Land Region and produces from various depths between 4,000 and 14,000 feet.

1 This excludes acreage for which we have incomplete seller records.

2 Refers to our average ownership interest. Ownership interest is the percentage that our undivided ownership interest in a tract bears to the entire tract. The average ownership interests shown reflect the weighted averages of our ownership interests in all tracts in the resource play. Our weighted average royalty interest for all of our mineral interests is approximately 20%, which may be multiplied by our ownership interest to approximate the average net royalty interest for our mineral interests.

3 Refers to our average royalty interest. Average royalty interest is equal to the weighted-average percentage of production or revenues (before operating costs) that we are entitled to on a tract-by-tract basis in the resource play. NPRIs may be denominated as a “fractional royalty,” which entitles the owner to the stated fraction of gross production, or a “fraction of royalty,” where the stated fraction is multiplied by the lease royalty. In cases where our land documentation does not specify the form of NPRI, we have assumed a fractional royalty for purposes of the average royalty interests shown above.

1 We own both mineral and royalty interests and working interests in 437 of the wells shown in each column above.

2 Refers to mineral and royalty interest wells.

Estimated Proved Reserves

Evaluation and Review of Estimated Proved Reserves

The reserves estimates as of December 31, 2025, 2024, and 2023 shown herein have been independently evaluated by Netherland, Sewell & Associates, Inc. (NSAI), a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI summary reserves report incorporated herein is Mr. Connor B. Riseden. Mr. Riseden, a Licensed Professional Engineer in the State of Texas (License No. 100566), has been practicing consulting petroleum engineering at NSAI since 2006 and has over four years of prior industry experience. He graduated from Texas A&M University in 2001 with a Bachelor of Science Degree in Petroleum Engineering and from Tulane University in 2005 with a Master of Business Administration Degree. As technical principal, Mr. Riseden meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers and is proficient in judiciously applying industry standard practices to engineering evaluations as well as applying SEC and other industry reserves definitions and guidelines. NSAI does not own an interest in us or any of our properties, nor is it employed by us on a contingent basis. A copy of NSAI’s estimated proved reserve report, dated as of January 9, 2026 and effective as of December 31, 2025, is attached as Exhibit 99.1 to this Annual Report.

We maintain an internal staff of petroleum engineers and geoscience professionals who worked closely with our third-party reserve engineers to ensure the integrity, accuracy, and timeliness of the data used to calculate our estimated proved reserves. Our internal technical team members met with our third-party reserve engineers periodically during the period covered by the above referenced reserve report to discuss the assumptions and methods used in the reserve estimation process. We provided historical information to the third-party reserve engineers for our properties, such as oil and natural gas production, well test data, realized commodity prices, and operating and development costs. We also provided ownership interest information with respect to our properties. Stephanie Parish, our Manager, Reserves, was primarily responsible for overseeing the preparation of our reserve estimates for 2025 and 2024. Ms. Parish is a petroleum engineer with approximately 27 years of reservoir-engineering experience. Garrett Gremillion, our former Vice President, Engineering, was primarily responsible for overseeing the preparation of our reserve estimates for 2023. Mr. Gremillion is a petroleum engineer and had approximately 14 years of reservoir-engineering experience as of December 31, 2023.

Our historical proved reserve estimates were prepared in accordance with our internal control procedures. Throughout the year, our technical team met with NSAI to review properties and discuss evaluation methods and assumptions used in the proved reserves estimates, in accordance with our prescribed internal control procedures. Our internal controls over the reserves estimation process include verification of input data used in the reserves evaluation software as well as reviews by our internal engineering staff and management, which include the following:

•Comparison of historical operating expenses from the lease operating statements to the operating costs input in the reserves database;

•Review of working interests, net revenue interests, and royalty interests in the reserves database against our well ownership system;

•Review of historical realized commodity prices and differentials from index prices compared to the differentials used in the reserves database;

•Evaluation of capital cost assumptions derived from Authority for Expenditure estimates received;

•Review of actual historical production volumes compared to projections in the reserve report;

•Discussion of material reserve variances among our internal reservoir engineers; and

•Review of preliminary reserve estimates by our senior management with our internal technical staff.

Estimation of Proved Reserves

In accordance with rules and regulations of the SEC applicable to companies involved in oil and natural gas producing activities, proved reserves are those quantities of oil and natural 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. The term “reasonable certainty” means deterministically, the quantities of oil and/or natural gas are much more likely to be achieved than not, and probabilistically, there should be at least a 90% probability of recovering volumes equal to or exceeding the estimate. All our estimated proved reserves as of December 31, 2025, 2024, and 2023 are based on deterministic methods. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by using reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.

To establish reasonable certainty with respect to our estimated net proved reserves, NSAI used technical data including, but not limited to, well test data and production data. Reserves attributable to producing wells with sufficient production history were estimated using appropriate decline curves or other performance relationships. Reserves attributable to producing wells with limited production history and for undeveloped locations were estimated using performance from analogous wells in the surrounding area and geologic data to assess the reservoir continuity.

Summary of Estimated Proved Reserves

Estimates of reserves are prepared using oil and natural gas prices equal to the 12-month unweighted arithmetic average of the first-day-of-the-month price for each month within the year the estimates are prepared. For estimates of oil reserves, the average WTI spot oil prices used were $66.01,$76.32, and$78.21 per barrel as of December 31, 2025, 2024, and 2023, respectively. These average prices are adjusted for quality, transportation fees, and market differentials. For estimates of natural gas reserves, the average Henry Hub prices used were$3.39,$2.13, and$2.64 per MMBtu as of December 31, 2025, 2024, and 2023, respectively. These average prices are adjusted for energy content, transportation fees, and market differentials. Natural gas prices are also adjusted to account for NGL revenue since there is not sufficient data to account for NGL volumes separately in the reserve estimates. These reserve estimates exclude NGL quantities. When taking these adjustments into account, the average adjusted prices weighted by production over the remaining lives of the properties were $63.40 per barrel for oil and $3.37 per Mcf for natural gas as of December 31, 2025, $74.14 per barrel for oil and $2.22 per Mcf for natural gas as of December 31, 2024, and $76.90 per barrel for oil and $2.63 per Mcf for natural gas as of December 31, 2023.

Reserve estimates do not include any value for probable or possible reserves that may exist. The reserve estimates represent our net revenue interest and royalty interest in our properties. Although we believe these estimates are reasonable, actual future production, cash flows, taxes, development expenditures, operating expenses, and quantities of recoverable oil and natural gas may vary substantially from these estimates.

The following table presents our estimated proved oil and natural gas reserves:

Reserve engineering is a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary for the same property. In addition, the results of drilling, testing, and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately recovered. Estimates of economically recoverable oil and natural gas and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices, and future production rates and costs. Please read Part I, Item 1A. “Risk Factors.”

The estimated proved reserve report as of December 31, 2025 is included as an exhibit to this Annual Report. See "Note 2 - Summary of Significant Accounting Policies" to the consolidated financial statements and our "Supplemental Oil and Natural Gas Disclosures" included elsewhere in this Annual Report for additional information.

Estimated Proved Undeveloped Reserves

As of December 31, 2025, our PUDs comprised 395 MBbls of oil and 37,625 MMcf of natural gas, or 6,666 MBoe. PUDs will be converted from undeveloped to developed as the applicable wells begin production.

The following table summarizes our changes in PUDs during the year ended December 31, 2025 (in MBoe):

New PUD reserves totaling 5,064 MBoe were added during the year ended December 31, 2025, resulting from development activities in the Haynesville/Bossier play and the Permian Basin. In 2025 we did not acquire or divest any PUD reserves.

During the year ended December 31, 2025, PUD revisions accounted for a 777 MBoe increase in reserves and 2,272 MBoe of PUD reserves were converted to proved developed reserves.

During the year ended December 31, 2025, no costs were incurred relating to the development of locations that were classified as PUDs as of December 31, 2024. The PUDs that were developed during 2025 were primarily Haynesville/Bossier PUDs in which our working interest was farmed out. Additionally, during the year ended December 31, 2025, we incurred$0.6 million drilling, completing, and recompleting other wells that were not classified as PUDs as of December 31, 2024. There are no estimated future development costs projected for the development of PUD reserves associated with our working interests as of December 31, 2025. All our PUD drilling locations as of December 31, 2025 are scheduled to be drilled within five years from the date the reserves were initially booked as proved undeveloped reserves.

We generally do not have evidence of approval of our operators’ development plans. As a result, our proved undeveloped reserve estimates are limited to those relatively few locations for which we have development agreements in place or have received evidence of capital commitment. As of December 31, 2025, our PUD reserves consists of 35 wells in various stages of drilling or completions. As of December 31, 2025, approximately 12% of our total proved reserves were classified as PUDs.

Oil and Natural Gas Production Prices and Production Costs

Production and Price History

For the year ended December 31, 2025, 26% of our production and 52% of our oil and natural gas revenues were related to oil and condensate production and sales, respectively. During the same period, natural gas and NGLs were 74% of our production and 48% of our oil and natural gas revenues.

The following table sets forth information regarding production of oil and natural gas and certain price and cost information for each of the periods indicated:

1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data by our operators. As a result, we are unable to reliably determine the total volumes of NGLs associated with the production of natural gas on our acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in our natural gas revenue and our calculation of realized prices for natural gas.

Productive Wells

Productive wells consist of producing wells, wells capable of production, and exploratory, development, or extension wells that are not dry wells.

The following table sets forth information about our mineral and royalty interest and working interest wells:

1 We own both mineral and royalty interests and working interests in 1,991 gross wells.

Acreage

Mineral and Royalty Interests

The following table sets forth information relating to our acreage for our mineral and royalty interests as of December 31, 2025:

1 Includes acreage for mineral interests, NPRIs, and ORRIs.

Working Interests

The following table sets forth information relating to our acreage for our non-operated working interests as of December 31, 2025:

Undeveloped Acreage

The following table lists our net undeveloped acres leased from third party mineral owners, the net acres expiring in the years ending December 31, 2026, 2027, and 2028, and, where applicable, the net acres expiring that are subject to extension options:

1 There are 12,845 undeveloped acres expiring between 2029 and 2032, and where applicable, subject to extension options.

Drilling Results for Our Working Interests

The following table sets forth information with respect to the number of wells in which we own a working interest completed on our properties during the periods indicated, excluding wells subject to our farmout agreements. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation among the number of productive wells drilled, the quantities of reserves found, and the economic value. Productive wells are those that produce commercial quantities of hydrocarbons, whether or not they produce a reasonable rate of return.

As of December 31, 2025, we had no wells in the process of drilling, completing or dewatering, or shut in awaiting infrastructure.

Environmental Matters

Oil and natural gas exploration, development, and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. These laws and regulations have the potential to impact production on our properties, which could materially adversely affect our business and our prospects. Numerous federal, state, and local governmental agencies, such as the U.S. Environmental Protection Agency (“EPA”), issue regulations that carry substantial administrative, civil, and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may delay or create significant financial burdens on operators' ability to explore for, develop, and produce oil and gas from our properties. The strict, joint, and several liability nature of such laws and regulations could impose liability upon our operators, or us as working interest owners if the operator fails to perform, regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, or other waste products into the environment. In addition, many environmental statutes contain citizen suit provisions, and environmental groups frequently use these provisions to oppose oil and natural gas exploration and development activities and related projects. The long-term trend in environmental regulation has been towards more stringent regulations, and any changes that impact our operators and result in more stringent and costly pollution control or waste handling, storage, transport, disposal, or cleanup requirements could materially adversely affect our business and prospects. Below is a summary of environmental laws applicable to operations on our properties.

Waste Handling

The Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development, and production activities by imposing requirements regarding waste handling. Individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. While waste products from the exploration, development and production of oil and natural gas typically constitute “solid wastes” that are subject to less stringent non-hazardous waste requirements, RCRA could be amended or the EPA or state environmental agencies could adopt policies to require those waste products to become subject to more stringent waste handling requirements. Any changes in the laws and regulations could have a material adverse effect on our operators’ capital expenditures and operating expenses, which in turn could affect production from our properties and adversely affect our business and prospects.

Remediation of Hazardous Substances

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and analogous state laws generally impose strict, joint, and several liability, without regard to fault or legality of the original conduct, for the release of a “hazardous substance” into the environment. Parties subject to liability include the current owner or operator of a contaminated facility (which can include working interest owners), a former owner or operator of the facility at the time of contamination, and those persons that disposed or arranged for the disposal of the hazardous substance at the facility. These “responsible parties” may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to natural resources and for the costs of certain health studies. Oil and natural gas exploration and production activities on our properties use materials that, if released, would be subject to these laws.

Water Discharges

The Federal Water Pollution Control Act of 1972, also known as the “Clean Water Act” (“CWA”), the Safe Drinking Water Act (“SDWA”), the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States, as well as state waters.

Under the CWA, the discharge of pollutants into jurisdictional wetlands or other federally regulated waters of the United States ("WOTUS") is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The CWA and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). The scope of jurisdiction under the CWA remains uncertain at this time. In November 2025, the EPA and the Corps proposed a rule to further update the definition of WOTUS, guided by the U.S. Supreme Court’s Sackett v. EPA decision. Accordingly, any change in the CWA’s jurisdiction could result in increased costs or delays with respect to obtaining permits for certain activities for our operators. In addition, spill prevention, control, and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture, or leak. The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

The OPA is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint, and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil into surface waters.

The SDWA grants the EPA broad authority to take action to protect public health when an underground source of drinking water is threatened with pollution that endangers humans, which could result in orders prohibiting or limiting the operations of oil and natural gas production facilities. The EPA has asserted regulatory authority pursuant to the SDWA's Underground Injection Control ("UIC") program over hydraulic fracturing activities involving the use of diesel fuel in fracturing fluids and issued guidance covering such activities. The SDWA also regulates saltwater disposal wells under the UIC Program. Concerns related to the operation of saltwater disposal wells and induced seismicity have led some states to impose limits on the total volume of produced water such wells can dispose of, order disposal wells to cease operations, or limit the construction of new wells. These seismic events have also resulted in environmental groups and local residents filing lawsuits against operators in areas where the events occur seeking damages and injunctions limiting or prohibiting saltwater disposal well construction activities and operations. A lack of saltwater disposal wells in production areas could result in increased disposal costs for our operators if they are forced to transport produced water by truck, pipeline, or other method over long distances, or force them to curtail operations.

Noncompliance with the Clean Water Act, SDWA, or the OPA may result in substantial administrative, civil, and criminal penalties, as well as injunctive obligations, all of which could affect production from our properties and adversely affect our business and prospects.

Air Emissions

The federal Clean Air Act ("CAA") and comparable state laws and regulations regulate emissions of various air pollutants. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. To the extent these laws and regulations apply to our operators, they may increase the costs of compliance for oil and natural gas producers and impact production on our properties, and federal and state regulatory agencies can impose administrative, civil, and criminal penalties for non-compliance with air permits or other requirements of the federal Clean Air Act and associated state laws and regulations. Moreover, obtaining or renewing permits has the potential to delay the development of oil and natural gas exploration and development projects. All of these factors could impact production on our properties and adversely affect our business and results of operations.

Climate Change

The threat of climate change continues to attract considerable attention. Numerous proposals have been made and could continue to be made at the international, national, regional, and state levels of government to monitor and limit existing emissions of greenhouse gases ("GHG") as well as to restrict or eliminate such future emissions. As a result, our operations as well as the operations of our operators are subject to a series of regulatory, political, litigation, and financial risks associated with the production and processing of fossil fuels and emission of GHGs.

In the United States, no comprehensive climate change legislation has been implemented at the federal level and, following the change in U.S. presidential administrations, proposals have been made to repeal or otherwise modify climate change-related requirements and the EPA’s GHG “Endangerment Finding.” In February 2026, the Trump administration finalized a rule repealing the Endangerment Finding. This served as the basis for the majority of the EPA’s GHG regulations, including existing rules that establish construction and operating permit reviews for GHG emissions from certain large stationary sources and require the monitoring and annual reporting of GHG emissions. It is uncertain at this time what impact the repeal of the Endangerment Finding will have on such regulations.

Relatedly, the regulation of methane from oil and natural gas facilities has been subject to uncertainty in recent years. In December 2023, the EPA finalized more stringent methane rules for new, modified, and reconstructed facilities, known as New Source Performance Standard ("NSPS") OOOOb, as well as rules for existing sources for the first time ever, known as OOOOc. The rules have been subject to legal challenge. In March 2025, the EPA announced plans to reconsider OOOOb and OOOOc, in line with the Trump administration’s deregulatory agenda. Most recently, in November 2025, the EPA finalized an interim rule extending the compliance deadlines for certain provisions provided in OOOOb and OOOOc. Litigation challenging the EPA’s final interim rule extending such compliance deadlines for new and existing oil and natural gas sources remains pending.

Separately, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, climate “superfund” laws, reporting and tracking programs, and restriction of emissions.

Litigation risks are also increasing as a number of cities and other local governments have sought to bring suit against the largest oil and natural gas companies in state or federal court, alleging among other things, that such companies created public nuisances by producing fuels that contributed to climate change or alleging that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose such impacts to their investors or customers. Recently, there have also been a number of lawsuits filed against companies alleging that such companies have made misleading or unsubstantiated claims with respect to the environmental benefits of their products or services, also known as greenwashing.

There have also recently been increasing financial risks for fossil fuel producers as certain shareholders currently invested in fossil-fuel energy companies have shown that they may elect in the future to shift some or all of their investments into non-energy related sectors. Institutional lenders may elect not to provide funding for fossil fuel energy companies, although this trend has waned recently, with several high-profile banks and institutional investors withdrawing from various associations that aim to limit the financing of such industries. Limitation of investments in and financing for fossil fuel energy companies could result in the restriction, delay, or cancellation of drilling programs or development or production activities.

Climate change may also result in various physical risks, such as the increased frequency and intensity of extreme weather events or changes in meteorological and hydrological patterns or other physical disruptions, that could adversely impact our operations, as well as those of our operators. Such physical risks may result in damage to operators’ facilities or otherwise adversely impact their operations, such as becoming subject to water use curtailments in response to drought, or experiencing reduced demand for their heating products in response to warmer winters.

Hydraulic Fracturing

Our operators engage in hydraulic fracturing to stimulate production of hydrocarbons from tight formations, including shales. The process involves the injection of water, sand, and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions, but the EPA and other federal agencies have asserted jurisdiction over certain aspects of hydraulic fracturing, although this has lessened following the change of presidential administrations.

Several states where we own interests in oil and gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, New Mexico, and Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids. For example, Texas, Oklahoma, and New Mexico have imposed certain limits on the permitting or operation of disposal wells in areas with increased instances of induced seismic events. These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position.

In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of well drilling in general or hydraulic fracturing in particular. Colorado legislation, for example, includes establishment of more stringent setbacks (2,000 feet instead of 500-feet) on new oil and gas development and the elimination of routine flaring and venting of natural gas at new or existing wells across the state, and its environmental regulatory commission adopted regulations aimed at curbing methane emissions from oil and gas operations. Additionally, in March 2025, the Colorado Energy and Carbon Management Commission issued regulations requiring instate operators to phase in the use of recycled produced water for hydraulic fracturing, with minimum recycling targets starting at 2% in 2026 and increasing over time (potentially up to 35% by 2038), which may result in additional costs for water treatment infrastructure, recycling facilities, and related compliance measures. Overall, we cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests. In the event state, local, or municipal legal restrictions are adopted in areas where our operators conduct operations, our operators may incur substantial costs to comply with these requirements, which may be significant in nature, experience delays, or curtailment in the pursuit of exploration, development, or production activities and perhaps even be precluded from the drilling of wells.

There has been controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices. If new laws or regulations are adopted that significantly restrict hydraulic fracturing, those laws could make it more difficult or costly for our operators to perform fracturing to stimulate production from tight formations. In addition, if hydraulic fracturing is further regulated at the federal or state level, fracturing activities on our properties could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, and also to attendant permitting delays and potential increases in costs. Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Occupational Safety and Health Act

The Occupational Safety and Health Act (“OSHA”) and comparable state laws and regulations govern the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations, and similar state statutes and regulations require that information be maintained about hazardous materials used or produced in operations on our properties and that this information be provided to employees, state and local government authorities, and citizens.

Endangered Species

The Endangered Species Act (“ESA”) and analogous state laws restrict activities that may affect endangered or threatened species or their habitats. Some of our properties may be located in areas that are or may be designated as habitats for endangered or threatened species, and previously unprotected species may later be designated as threatened or endangered in areas where we hold interests. The listing of species in areas where we hold interests could cause our operators to incur increased costs arising from species protection measures, delay the completion of exploration and production activities, and/or result in limitations on operating activities that could have an adverse impact on our business.

Title to Properties

Prior to completing an acquisition of oil and natural gas properties, we perform title reviews on high-value tracts. Our title reviews are meant to confirm quantum of oil and natural gas properties being acquired, lease status, and royalties as well as encumbrances and other related burdens. Depending on the materiality of properties, we may obtain a title opinion if we believe additional title due diligence is necessary. As a result, title examinations have been obtained on a significant portion of our properties. After an acquisition, we review the assignments from the seller for scrivener’s and other errors and execute and record corrective assignments as necessary.

In addition to our initial title work, our operators conduct a thorough title examination prior to leasing and drilling a well. Should our operators’ title work uncover any title defects, either we or our operators will perform curative work with respect to such defects. Our operators generally will not commence drilling operations on a property until any material title defects on such property have been cured.

We believe that the title to our assets is satisfactory in all material respects. Although title to these properties is subject to encumbrances in some cases, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions, and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens, and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

Major Customers (Operators)

If we were to lose a significant operator on our properties, that loss could negatively affect revenue derived from our mineral and royalty interest or working interest properties. The loss of any single lessee is mitigated by our diversified operator base. Aethon represented approximately 14% of total oil and natural gas revenues for the year ended December 31, 2025; Pioneer Natural Resources and XTO Energy, subsidiaries of ExxonMobil Corporation, collectively represented approximately 13% of total oil and natural gas revenues for the year ended December 31, 2024; and no single operator exceeded 10% of total oil and natural gas revenues for the year ended December 31, 2023.

Competition

The oil and natural gas business is highly competitive in the exploration for and acquisition of reserves, the acquisition of minerals and oil and natural gas leases, and personnel required to find and produce reserves. Many companies not only explore for and produce oil and natural gas, but also conduct midstream and refining operations and market petroleum and other products on a regional, national, or worldwide basis. Certain of our competitors may possess financial or other resources substantially larger than we possess. Our ability to acquire additional minerals and properties and to discover reserves in the future will be dependent upon our ability to identify and evaluate suitable acquisition prospects and to consummate transactions in a highly competitive environment. Oil and natural gas products compete with other sources of energy available to customers, primarily based on price. These alternate sources of energy include coal, nuclear, solar, and wind. Changes in the availability or price of oil and natural gas or other sources of energy, as well as business conditions, conservation, legislation, regulations, and the ability to convert to alternate fuels and other sources of energy may affect the demand for oil and natural gas.

Seasonal Nature of Business

Weather conditions affect the demand for, and prices of, natural gas and can also delay drilling activities, disrupting our overall business plans. Demand for natural gas is typically higher during the winter, resulting in higher natural gas prices for our natural gas production during our first and fourth quarters. Certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can lessen seasonal demand fluctuations. Seasonal weather conditions can limit drilling and producing activities and other oil and natural gas operations in a portion of our operating areas. Due to these seasonal fluctuations, our results of operations for individual quarterly periods may not be indicative of the results that we may realize on an annual basis.

Human Capital

Overview and Structure. We consider our workforce to be our most important asset, and we have sought to structure our hiring practices, compensation and benefits programs, and employee practices to attract and retain high-quality personnel and to provide a comfortable and collegial work environment. We continue to invest in our employees by providing training opportunities, promoting diversity and inclusion, and maintaining focus on corporate ethics. We are managed and operated by the Board and executive officers of our general partner. All our employees, including our executive officers, are employees of Black Stone Natural Resources Management Company (“Black Stone Management”).

Headcount. We rely principally on full-time employees but use independent contractors as needed to assist with special projects. As of December 31, 2025, Black Stone Management had 122 full-time employees and 7 contractors. Our largest departments are Accounting and Land Administration, which account for 37 and 23 respectively, of our full-time employee base. None of Black Stone Management’s employees are represented by labor unions or covered by any collective bargaining agreements.

Recruiting. As a small, tight-knit group, our employees have broad responsibilities, and we encourage continuing development in their careers. When new opportunities arise within our organization, we have a multi-faceted approach to fill those positions including looking within our workforce for talent to fill those needs, asking for referrals from our team members (who understand the diverse skill sets, high energy and forward-thinking attitude that contributes to delivering exceptional results), posting open positions to our public-facing website, and working with recruiters who specialize in the areas of our vacancies.

Compensation. As part of our efforts to hire and retain highly qualified employees, we have structured compensation and benefits programs that, we believe, are extremely competitive and reward outstanding performance. In addition to the incentive programs in place for our named executive officers, which are described in detail in our proxy statement, we have structured a cash-bonus program for non-officer employees that is dependent on an employee’s individual performance and our performance as a company. Certain employees also receive restricted-unit and performance-unit awards to encourage retention and align compensation with our company performance.

Healthcare and Other Benefits. We provide a robust suite of benefits to our employees covering all aspects of life, including 401(k) matching, medical-insurance options, and programs to encourage and support the whole person, including physical, mental and emotional, financial, social, career, and community service initiatives. Within these listed programs we provide, free to all employees, dental and vision insurance covering an employee’s entire family, caregiver support benefits, a personal financial wellness program, a tuition-reimbursement program, a building-provided fitness center, employee health care advocacy services, a wellness program providing employees the ability to earn lifestyle rewards for participating in healthy activities as well as a recognition program to celebrate milestone service awards and other moments of excellence.

Hybrid Work Environment. The majority of our employees have work flexibility which allows for work outside of the office on Monday and Friday, and requires work in the office on Tuesday through Thursday during core business hours. This arrangement allows employees to have a greater work-life balance, and we believe the ability to work in a hybrid environment, as well as our robust compensation and benefits program, allow us to retain and recruit top-quality employees.

Facilities

Our principal office location is in Houston, Texas and consists of 55,862 square feet of leased space.