Black Stone Minerals, L.P. Announces Fourth Quarter and Full Year 2025 Results; Provides Guidance for 2026

View all news 02/23/2026 Black Stone Minerals, L.P. (NYSE: BSM) (“Black Stone Minerals,” “Black Stone,” or “the Partnership”) today announces its financial and operating results for the fourth quarter and full year of 2025 and provides guidance for 2026. Fourth Quarter 2025 Highlights Mineral and royalty production for the fourth quarter of 2025 equaled 30.9 MBoe/d; total production, including working interest volumes, was 32.1 MBoe/d for the quarterNet income for the quarter was $72.2 million. Adjusted EBITDA for the quarter totaled $76.7 millionDistributable Cash Flow was $66.8 million for the fourth quarterBlack Stone announced a distribution of $0.30 per common unit with respect to the fourth quarter of 2025; distribution coverage for all units was 1.05xTotal debt at the end of the quarter was $154.0 million; as of February 20, 2026, total debt was $156.0 million with $5.1 million of cash Full Year Financial and Operational Highlights Mineral and royalty volumes in 2025 decreased 9% over the prior year to average 33.3 MBoe/d; average full year 2025 production was 34.6 MBoe/dReported 2025 net income and Adjusted EBITDA of $299.9 million and $337.4 million, respectivelyCash distributions attributable to the full year 2025 were $1.28 per common unitAcquired $114.5 million of mineral and royalty interestsNew development agreements with Revenant Energy and Caturus Energy in the Shelby Trough and Haynesville expansion areas, adding minimum drilling commitments equivalent to 8 wells in 2026, ramping to 37 wells by 2031 Management Commentary “Over the course of 2025, the Black Stone team executed across all commercial initiatives, advancing Black Stone’s long-term growth,” said Fowler Carter, Co-CEO and President. “We signed multiple development agreements covering 490,000 gross acres and have deployed $239.5 million through our acquisition program since September 2023 to build the Haynesville expansion asset, which extends around the Shelby Trough and towards the Western Haynesville. Across our other assets we had a strong leasing program in 2025, primarily focused in the Permian, and we anticipate another significant, high-interest development in the southern Delaware Basin in addition to the ongoing Coterra activity in Culberson County. “In the Haynesville expansion area, we are looking forward to Revenant and Caturus initiating their development programs in 2026, where we expect Revenant will outperform its minimum obligation and Caturus will drill multiple wells, including a pilot well stepping further west towards Houston County. Aethon is also planning to drill 18 wells throughout 2026. In addition to these development programs, we are building new opportunities to further expand our asset base and add new development agreements in the Shelby Trough and Haynesville expansion area to further increase long-term growth for our unitholders.” Taylor DeWalch, Co-CEO and President commented, “We are looking forward to a successful full year 2026, where we expect to start realizing production growth, driven primarily by development agreements in the Shelby Trough and high-interest activity in the Permian. As reflected in our updated guidance last year, we anticipated 2025 production to decline due to reduced activity in the Shelby Trough since late 2023, and for the year, production came in at the high end of that guidance. While we ended 2025 and start 2026 with lower production, we expect to see a significant production increase throughout the year and continued growth in the years to come. This pivotal year points to long-term production and distribution growth, as activity is projected to increase in the Shelby Trough, primarily through Aethon, Revenant, and Caturus surpassing previous activity levels and ultimately expected to reach the equivalent of over 50 wells per year, in the aggregate, based on minimum obligations. “Importantly, we are maintaining our financial discipline with a solid balance sheet as we continue our strategic, grass roots mineral acquisition program, which combined with recent development agreements and comprehensive asset management, drives meaningful long-term value for the Partnership’s unitholders.” Quarterly Financial and Operating Results Production Black Stone Minerals reported mineral and royalty volumes of 30.9 MBoe/d (74% natural gas) for the fourth quarter of 2025, compared to 34.7 MBoe/d for the third quarter of 2025 and 34.8 MBoe/d for the fourth quarter of 2024. Working interest production was 1.2 MBoe/d in the fourth quarter of 2025, 1.6 MBoe/d for the third quarter of 2025, and 1.3 MBoe/d for the fourth quarter of 2024. Total reported production averaged 32.1 MBoe/d (96% mineral and royalty, 74% natural gas) for the fourth quarter of 2025, compared to 36.3 MBoe/d and 36.1 MBoe/d for the third quarter of 2025 and the fourth quarter of 2024, respectively. Realized Prices, Revenues, and Net Income The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was $30.63 for the fourth quarter of 2025. This is an increase of 2% from $30.01 per Boe for the third quarter of 2025 and a 1% decrease compared to $30.81 for the fourth quarter of 2024. Black Stone reported oil and gas revenue of $90.5 million (51% oil and condensate) for the fourth quarter of 2025, a decrease of 10% from $100.2 million in the third quarter of 2025. Oil and gas revenue in the fourth quarter of 2024 was $102.3 million. The Partnership reported a gain on commodity derivative instruments of $23.5 million for the fourth quarter of 2025, composed of a $4.5 million gain from realized settlements and a non-cash $19.0 million unrealized gain due to the change in value of Black Stone’s derivative positions during the quarter. Black Stone reported a gain on commodity derivative instruments of $27.3 million and a loss of $20.6 million for the quarters ended September 30, 2025 and December 31, 2024, respectively. Lease bonus and other income was $4.7 million for the fourth quarter of 2025. Lease bonus and other income for the third quarter of 2025 and fourth quarter of 2024 was $5.0 million and $2.0 million, respectively. The Partnership reported net income of $72.2 million for the fourth quarter of 2025, compared to net income of $91.7 million in the preceding quarter. For the fourth quarter of 2024, the Partnership reported net income of $46.3 million. Adjusted EBITDA and Distributable Cash Flow Adjusted EBITDA for the fourth quarter of 2025 was $76.7 million, which compares to $88.1 million in the third quarter of 2025 and $90.2 million in the fourth quarter of 2024. Distributable Cash Flow for the quarter ended December 31, 2025 was $66.8 million. For the third quarter of 2025 and fourth quarter of 2024, Distributable Cash Flow was $78.6 million and $82.0 million, respectively. Each period reflects the Partnership’s revised definitions of Adjusted EBITDA and Distributable Cash Flow, which exclude seismic data acquisition costs (see “Non-GAAP Financial Measures”). 2025 Proved Reserves Estimated proved oil and natural gas reserves at year-end 2025 were 54.8 MMBoe, a decrease of 4% from 57.4 MMBoe at year-end 2024, and were approximately 70% natural gas and 88% proved developed producing. The standardized measure of discounted future net cash flows was $889.2 million at the end of 2025, as compared to $868.1 million at year-end 2024. Netherland, Sewell and Associates, Inc., an independent, third-party petroleum engineering firm, evaluated Black Stone Minerals’ estimate of its proved reserves and PV-10 at December 31, 2025. These estimates were prepared using reference prices of $66.01 per barrel of oil and $3.39 per MMBTU of natural gas in accordance with the applicable rules of the Securities and Exchange Commission (as compared to prompt month prices of $66.39 per barrel of oil and $3.05 per MMBTU of natural gas as of February 20, 2026). These prices were adjusted for quality and market differentials, transportation fees, and, in the case of natural gas, the value of natural gas liquids. A reconciliation of proved reserves is presented in the summary financial tables following this press release. Financial Position and Activities As of December 31, 2025, Black Stone Minerals had $1.5 million in cash, with $154.0 million drawn under its credit facility. The Partnership’s borrowing base at December 31, 2025 was $580.0 million, and total commitments under the credit facility were $375.0 million. The Partnership’s next regularly scheduled borrowing base redetermination is set for April 2026. Black Stone is in compliance with all financial covenants associated with its credit facility. As of February 20, 2026, $156.0 million debt was outstanding under the credit facility and the Partnership had $5.1 million in cash. Fourth Quarter 2025 Distributions As previously announced, the Board approved a cash distribution of $0.30 for each common unit attributable to the fourth quarter of 2025. The quarterly distribution coverage ratio attributable to the fourth quarter of 2025 was approximately 1.05x. The distribution will be paid on February 25, 2026 to unitholders of record as of the close of business on February 18, 2026. Activity Update Development Activity During the fourth quarter, Aethon Energy was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. Aethon’s development program remains on track, with 6 wells spud in the second half of 2025 as part of the current program year ending June 30, 2026, an additional 8 wells expected in the first half of 2026 to complete that program year, and 10 more wells expected in the second half of 2026 as part of the next program year. Aethon successfully turned to sales 7 gross (0.42 net) wells during the fourth quarter and has an inventory of 5 gross (0.31 net) wells from the previous program year that it expects to turn to sales during early 2026. Black Stone’s agreement with Revenant Energy covers 270,000 gross acres in which the Partnership currently controls approximately 122,000 undeveloped net acres. Revenant is obligated to drill a minimum of 6 wells in 2026, increasing annually to a minimum of 25 wells per year by 2030. The Partnership has also secured a non-operated working interest partner for the development. In November 2025, the agreement was amended to maintain the 6-well commitment for 2026 and convert future commitments to completed gross lateral-foot targets at one well per 7,000 lateral feet, allowing longer laterals while keeping overall development levels unchanged. Revenant expects to spud more wells than its 6-well commitment for the first program year ending December 31, 2026. In November 2025, Black Stone entered into a 220,000 gross acre development agreement with Caturus Energy, which aims to push the Shelby Trough westward towards the Western Haynesville. Activity will begin with approximately 2 gross (0.2 net) wells in 2026 and ramp to approximately 12 gross (0.8 net) wells annually by 2031, supported by minimum annual lateral-foot requirements, all net to Black Stone’s interest. In addition to the 2 gross wells in 2026, Caturus plans to drill a pilot well stepping out towards Houston County, consistent with the terms of the agreement. In the Permian Basin, the Partnership continues to monitor activity, including two large-scale developments expected to generate meaningful liquids volumes in 2026 and beyond. Coterra Energy continues to develop our acreage in Culberson County, Texas. During the third quarter, 5 gross wells (0.17 net) were turned to sales, with the remaining 34 gross (1.21 net) wells expected in the first half of 2026. A second large development of 30 gross (2.04 net) wells in the southern Delaware Basin is expected to come online in the second half of 2026 and first half of 2027. Acquisition Activity The Partnership continues to acquire bolt-on acreage in multiple contractual development programs with significant inventory at high net interests across San Augustine, Nacogdoches, Angelina, Cherokee, Houston, and Trinity counties. In the fourth quarter of 2025, Black Stone acquired $48.8 million of additional (primarily non-producing) mineral and royalty interests. From the inception of this acquisition program in September 2023 through December 2025, the Partnership has completed $239.5 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area. Black Stone’s commercial strategy going forward includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement the Partnership’s existing positions. Summary 2026 Guidance Following are the key assumptions in Black Stone Minerals’ 2026 guidance, as well as comparable results for 2025: FY 2025 Actual FY 2026 Est. Mineral and royalty production (MBoe/d) 33.3 32.5 - 34.5 Working interest production (MBoe/d) 1.3 0.5 - 1.5 Total production (MBoe/d) 34.6 33 - 36 Percentage natural gas 74% 77% Percentage royalty interest 96% 97% Lease bonus and other income ($MM) $21.4 $12 - 15 Lease operating expense ($MM) $10.1 $7 - 9 Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) 10% 9 - 11% Exploration Expense ($MM) $18.6 $28 - 32 G&A - cash ($MM) $45.9 $51 - 52 G&A - non-cash ($MM) $9.6 $11 - 13 G&A - TOTAL ($MM) $55.5 $62 - 65 DD&A ($/Boe) $2.92 $2.90 - 3.10 Black Stone expects full year 2026 royalty production to stay relatively flat compared to full year 2025; however, the Partnership expects production to build over the year, reaching higher levels by the fourth quarter of 2026. The anticipated increase is primarily attributable to Shelby Trough, Louisiana Haynesville, and key Delaware Basin projects, while the Partnership anticipates a moderation of activity across the rest of the Permian, as well as in the Bakken / Three Forks, Eagle Ford, and Austin Chalk. The Partnership expects general and administrative expenses to be slightly higher in 2026 due to inflationary costs, selective hires supporting the evaluation and marketing of Black Stone's undeveloped acreage positions and the management of recently signed development agreements with increasing activity in the Shelby Trough, and investments in software and data subscriptions supporting these growth initiatives and overall asset management across the Partnership’s acreage. In addition, exploration costs are projected to increase approximately 60% due to proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough area. The majority of remaining costs for these projects are expected to be incurred in 2026, with completion targeted for early 2027. Hedge Position Black Stone has commodity derivative contracts in place covering portions of its anticipated production for 2026 and 2027, including derivative contracts put in place after the end of the year. The Partnership’s hedge position as of February 20, 2026, is summarized in the following tables: Oil Hedge Position Oil Swap Volume Oil Swap Price MBbl $/Bbl 1Q26 615 $64.39 2Q26 615 $64.39 3Q26 615 $64.39 4Q26 615 $64.39 1Q27 330 $59.64 2Q27 330 $59.64 3Q27 330 $59.64 4Q27 330 $59.64 Natural Gas Hedge Position Gas Swap Volume Gas Swap Price BBtu $/MMBtu 1Q26 12,600 $3.73 2Q26 12,740 $3.73 3Q26 12,880 $3.73 4Q26 12,880 $3.73 1Q27 6,300 $3.93 2Q27 6,370 $3.93 3Q27 6,440 $3.93 4Q27 6,440 $3.93 More detailed information about the Partnership’s existing hedging program can be found in Black Stone’s Annual Report on Form 10-K, which is expected to be filed on or around February 24, 2026. Conference Call Black Stone Minerals will host a conference call and webcast for investors and analysts to discuss its results for the fourth quarter and full year of 2025 and outlook for 2026 on Tuesday, February 24, 2026 at 9:00 a.m. Central Time. Black Stone recommends participants who do not anticipate asking questions to listen to the call via the live broadcast available at http://investor.blackstoneminerals.com. Analysts and investors who wish to ask questions should dial (800) 715-9871 for domestic participants and (646)-307-1963 for international participants. The conference ID for the call is 8003975. A recording of the conference call will be available on Black Stone’s website. About Black Stone Minerals, L.P. Black Stone Minerals is one of the largest owners and managers of oil and natural gas mineral interests in the United States. The Partnership owns mineral interests and royalty interests in 41 states in the continental United States. Black Stone believes its 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. Forward-Looking Statements This news release includes forward-looking statements. All statements, other than statements of historical facts, included in this news release that address activities, events or developments that the Partnership expects, believes or anticipates will or may occur in the future are forward-looking statements. Terminology such as “will,” “may,” “should,” “expect,” “anticipate,” “plan,” “project,” “intend,” “estimate,” “believe,” “target,” “continue,” “potential,” the negative of such terms, or other comparable terminology often identify forward-looking statements. Except as required by law, Black Stone Minerals undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this news release. Investors are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this news release. All forward-looking statements are qualified in their entirety by these cautionary statements. These forward-looking statements involve risks and uncertainties, many of which are beyond the control of Black Stone Minerals, which may cause the Partnership’s actual results to differ materially from those implied or expressed by the forward-looking statements. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below, as wells as the Risk Factors section in our most recent annual report on Form 10-K: the Partnership’s ability to execute its business strategies;the volatility of realized oil and natural gas prices;the level of production on the Partnership’s properties;overall supply and demand for oil and natural gas, and regional supply and demand factors, delays, or interruptions of production;conservation measures and general concern about the environmental impact of the production and use of fossil fuels;the Partnership’s ability to replace its oil and natural gas reserves;general economic, business, or industry conditions including slowdowns, domestically and internationally, and volatility in the securities, capital, or credit markets;cybersecurity incidents, including data security breaches or computer viruses;competition in the oil and natural gas industry;the availability or cost of rigs, equipment, raw materials, supplies, oilfield services or personnel; andthe level of drilling activity by the Partnership’s operators, particularly in areas such as the Shelby Trough and the Haynesville, where the Partnership has concentrated acreage positions. BLACK STONE MINERALS, L.P. CONSOLIDATED STATEMENTS OF OPERATIONS (Unaudited) (In thousands, except per unit amounts) Three Months Ended December 31, Year Ended December 31, 2025 2024 2025 2024 REVENUE Oil and condensate sales $ 46,370 $ 59,949 $ 209,361 $ 269,061 Natural gas and natural gas liquids sales 44,106 42,364 191,616 157,907 Lease bonus and other income 4,706 1,981 21,351 12,461 Revenue from contracts with customers 95,182 104,294 422,328 439,429 Gain (loss) on commodity derivative instruments, net 23,521 (20,568 ) 47,591 (5,730 ) TOTAL REVENUE 118,703 83,726 469,919 433,699 OPERATING (INCOME) EXPENSE Lease operating expense 2,236 2,272 10,141 9,705 Production costs and ad valorem taxes 8,878 10,701 39,024 49,577 Exploration expense 9,624 156 18,634 2,735 Depreciation, depletion, and amortization 8,670 10,943 36,887 45,196 General and administrative 14,080 11,796 55,463 52,082 Accretion of asset retirement obligations 361 336 1,374 1,298 TOTAL OPERATING EXPENSE 43,849 36,204 161,523 160,593 INCOME FROM OPERATIONS 74,854 47,522 308,396 273,106 OTHER INCOME (EXPENSE) Interest and investment income 55 190 237 1,666 Interest expense (2,837 ) (1,130 ) (8,930 ) (3,109 ) Other income (expense), net 155 (236 ) 229 (337 ) TOTAL OTHER EXPENSE (2,627 ) (1,176 ) (8,464 ) (1,780 ) NET INCOME 72,227 46,346 299,932 271,326 Distributions on Series B cumulative convertible preferred units (7,367 ) $ (7,367 ) (29,466 ) (29,466 ) NET INCOME ATTRIBUTABLE TO THE GENERAL PARTNER AND COMMON UNITS $ 64,860 $ 38,979 $ 270,466 $ 241,860 ALLOCATION OF NET INCOME: General partner interest $ — $ — $ — $ — Common units 64,860 38,979 270,466 241,860 $ 64,860 $ 38,979 $ 270,466 $ 241,860 NET INCOME ATTRIBUTABLE TO LIMITED PARTNERS PER COMMON UNIT: Per common unit (basic) $ 0.31 $ 0.19 $ 1.28 $ 1.15 Per common unit (diluted) $ 0.31 $ 0.18 $ 1.28 $ 1.15 WEIGHTED AVERAGE COMMON UNITS OUTSTANDING: Weighted average common units outstanding (basic) 211,867 210,694 211,667 210,684 Weighted average common units outstanding (diluted) 212,117 211,078 211,729 210,780 The following table shows the Partnership’s production, revenues, realized prices, and expenses for the periods presented. Three Months Ended December 31, Year Ended December 31, 2025 2024 2025 2024 (Unaudited) (Dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 768 855 3,259 3,606 Natural gas (MMcf)1 13,118 14,794 56,237 62,984 Equivalents (MBoe) 2,954 3,321 12,632 14,103 Equivalents/day (MBoe) 32.1 36.1 34.6 38.5 Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 60.38 $ 70.12 $ 64.24 $ 74.61 Natural gas ($/Mcf)1 3.36 2.86 3.41 2.51 Equivalents ($/Boe) $ 30.63 $ 30.81 $ 31.74 $ 30.27 Revenue: Oil and condensate sales $ 46,370 $ 59,949 $ 209,361 $ 269,061 Natural gas and natural gas liquids sales1 44,106 42,364 191,616 157,907 Lease bonus and other income 4,706 1,981 21,351 12,461 Revenue from contracts with customers 95,182 104,294 422,328 439,429 Gain (loss) on commodity derivative instruments 23,521 (20,568 ) 47,591 (5,730 ) Total revenue $ 118,703 $ 83,726 $ 469,919 $ 433,699 Operating expenses: Lease operating expense $ 2,236 $ 2,272 $ 10,141 $ 9,705 Production costs and ad valorem taxes 8,878 10,701 39,024 49,577 Exploration expense 9,624 156 18,634 2,735 Depreciation, depletion, and amortization 8,670 10,943 36,887 45,196 General and administrative 14,080 11,796 55,463 52,082 Other expense: Interest expense 2,837 1,130 8,930 3,109 Per Boe: Lease operating expense (per working interest Boe) $ 20.43 $ 18.62 $ 20.53 $ 13.55 Production costs and ad valorem taxes 3.01 3.22 3.09 3.52 Depreciation, depletion, and amortization 2.94 3.30 2.92 3.20 General and administrative 4.77 3.55 4.39 3.69 1 As a mineral-and-royalty-interest owner, Black Stone Minerals is often provided insufficient and inconsistent data on natural gas liquid ("NGL") volumes by its operators. As a result, the Partnership is unable to reliably determine the total volumes of NGLs associated with the production of natural gas on its acreage. Accordingly, no NGL volumes are included in our reported production; however, revenue attributable to NGLs is included in natural gas revenue and the calculation of realized prices for natural gas. Non-GAAP Financial Measures Adjusted EBITDA and Distributable Cash Flow are supplemental non-GAAP financial measures used by Black Stone’s management and external users of the Partnership’s financial statements such as investors, research analysts, and others, to assess the financial performance of its assets and its ability to sustain distributions over the long term without regard to financing methods, capital structure, or historical cost basis. The Partnership defines Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, seismic data acquisition costs, non-cash equity-based compensation, unrealized gains and losses on commodity derivative instruments, and gains and losses on sales of assets, if any. Black Stone defines Distributable Cash Flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any. Beginning with the three months and year ended December 31, 2025, the Partnership revised its definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on the Partnership’s consolidated statements of operations. Comparative amounts for the three months and year ended December 31, 2024 for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation. Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests. Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of the Partnership’s financial performance. Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable U.S. GAAP financial measure. The Partnership’s computation of Adjusted EBITDA and Distributable Cash Flow may differ from computations of similarly titled measures of other companies. Three Months Ended December 31, Year Ended December 31, 2025 2024 2025 2024 (Unaudited) (In thousands, except per unit amounts) Net income $ 72,227 $ 46,346 $ 299,932 $ 271,326 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 8,670 10,943 36,887 45,196 Interest expense 2,837 1,130 8,930 3,109 Income tax expense (benefit) (101 ) 284 (137 ) 509 Accretion of asset retirement obligations 361 336 1,374 1,298 Seismic data acquisition costs 9,299 76 17,349 2,287 Equity-based compensation 2,397 1,799 9,620 8,564 Unrealized (gain) loss on commodity derivative instruments (18,981 ) 29,302 (36,602 ) 50,944 Adjusted EBITDA 76,709 90,216 337,353 383,233 Adjustments to reconcile to Distributable Cash Flow: Change in deferred revenue — (1 ) (3 ) (4 ) Cash interest expense (2,582 ) (858 ) (7,845 ) (2,030 ) Preferred unit distributions (7,367 ) (7,367 ) (29,466 ) (29,466 ) Distributable Cash Flow $ 66,760 $ 81,990 $ 300,039 $ 351,733 Total units outstanding1 212,334 211,138 Distributable Cash Flow per unit 0.314 0.388 1 The distribution attributable to the quarter ended December 31, 2025 is calculated using 212,333,793 common units as of the record date of February 18, 2026. Distributions attributable to the quarter ended December 31, 2024 were calculated using 211,137,816 common units as of the record date of February 18, 2025. Proved Oil & Gas Reserve Quantities A reconciliation of proved reserves is presented in the following table: Crude Oil (MBbl) Natural Gas (MMcf) Total (MBoe) Net proved reserves at December 31, 2024 17,466 239,481 57,380 Revisions of previous estimates 669 (2,732 ) 214 Purchases of minerals in place 70 943 227 Sales of minerals in place (24 ) (75 ) (37 ) Extensions, discoveries, and other additions 1,714 47,877 9,693 Production (3,259 ) (56,237 ) (12,632 ) Net proved reserves at December 31, 2025 16,636 229,257 54,845 Net Proved Developed Reserves December 31, 2024 17,466 220,901 54,283 December 31, 2025 16,241 191,632 48,179 Net Proved Undeveloped Reserves December 31, 2024 — 18,580 3,097 December 31, 2025 395 37,625 6,666 Source: Black Stone Minerals, L.P. View all news