Black Stone Minerals, L.P. Announces Fourth Quarter and Full Year 2025 Results; Provides Guidance for 2026
Key Terms
adjusted ebitda financial
distributable cash flow financial
proved reserves technical
standardized measure financial
borrowing base financial
dd&a financial
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 quarter
-
Net income for the quarter was
$72.2 million $76.7 million -
Distributable Cash Flow was
$66.8 million -
Black Stone announced a distribution of
$0.30 -
Total debt at the end of the quarter was
$154.0 million $156.0 million $5.1 million
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/d -
Reported 2025 net income and Adjusted EBITDA of
$299.9 million $337.4 million -
Cash distributions attributable to the full year 2025 were
$1.28 -
Acquired
$114.5 million - New 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
“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
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 (
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 (
Realized Prices, Revenues, and Net Income
The Partnership’s average realized price per Boe, excluding the effect of derivative settlements, was
Black Stone reported oil and gas revenue of
The Partnership reported a gain on commodity derivative instruments of
Lease bonus and other income was
The Partnership reported net income of
Adjusted EBITDA and Distributable Cash Flow
Adjusted EBITDA for the fourth quarter of 2025 was
2025 Proved Reserves
Estimated proved oil and natural gas reserves at year-end 2025 were 54.8 MMBoe, a decrease of
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
Financial Position and Activities
As of December 31, 2025, Black Stone Minerals had
As of February 20, 2026,
Fourth Quarter 2025 Distributions
As previously announced, the Board approved a cash distribution of
Activity Update
Development Activity
During the fourth quarter, Aethon Energy was operating three rigs on our
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
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
Acquisition Activity
The Partnership continues to acquire bolt-on acreage in multiple contractual development programs with significant inventory at high net interests across
In the fourth quarter of 2025, Black Stone acquired
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 |
|
|
|
Percentage royalty interest |
|
|
|
|
|
|
|
Lease bonus and other income ($MM) |
|
|
|
|
|
|
|
Lease operating expense ($MM) |
|
|
|
Production costs and ad valorem taxes (as % of total pre-derivative O&G revenue) |
|
|
9 - |
Exploration Expense ($MM) |
|
|
|
|
|
|
|
G&A - cash ($MM) |
|
|
|
G&A - non-cash ($MM) |
|
|
|
G&A - TOTAL ($MM) |
|
|
|
|
|
|
|
DD&A ($/Boe) |
|
|
|
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
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
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 |
|
2Q26 |
615 |
|
3Q26 |
615 |
|
4Q26 |
615 |
|
1Q27 |
330 |
|
2Q27 |
330 |
|
3Q27 |
330 |
|
4Q27 |
330 |
|
Natural Gas Hedge Position |
|
|
|
Gas Swap Volume |
Gas Swap Price |
|
BBtu |
$/MMBtu |
1Q26 |
12,600 |
|
2Q26 |
12,740 |
|
3Q26 |
12,880 |
|
4Q26 |
12,880 |
|
1Q27 |
6,300 |
|
2Q27 |
6,370 |
|
3Q27 |
6,440 |
|
4Q27 |
6,440 |
|
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
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; and
- the 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
|
|
Year Ended
|
||||||||||||
|
|
|
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
|
|
Year Ended
|
||||||||||
|
|
|
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
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
|
|
Three Months Ended
|
|
Year Ended
|
||||||||||||
|
|
|
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
|
|
Natural Gas
|
|
Total
|
|||
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 |
|
View source version on businesswire.com: https://www.businesswire.com/news/home/20260223282969/en/
Black Stone Minerals, L.P. Contacts
Chris Bonner
Senior Vice President, Chief Financial Officer, and Treasurer
Telephone: (713) 445-3200
investorrelations@blackstoneminerals.com
Source: Black Stone Minerals, L.P.
