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CLOSED · 03:15 ET
Market ClerkRecap
Sun Oct 25 · markets closed1 signal on Oct 2494 insider buys this week · $48.3MCIRO short report next: Oct 30The week ahead

BSM

Black Stone Minerals, L.P.
NYSE · ENERGY · CRUDE PETROLEUM & NATURAL GAS
14.97
+0.26 +1.77%
USD · close Oct 23
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Work order
83
PASS · shorts 83
Insiders, 90 days
0
no open-market filings in 90 days
Congress, 90 days
0 / 0
no disclosures naming it
Big money
0 / 15
none of the tracked funds disclose it
Calls on record
0
nobody we score has called it yet
MKT CAP —P/E —DIV YIELD —FCF YIELD —REV TTM $459.5M +5.1%NET INCOME $283.6M +3.1%NET CASH —52W 13.03 – 15.44SEC XBRL · TTM TO Invalid Date

How BSM rewrote its risk factors

10-K ITEM 1A · FY2024 → FY2025
Text kept
34%
of sentences unchanged
Added
368
new sentences
Dropped
350
sentences removed
Length
+922
words, now 26,923

New in FY2025

  • Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2025 and 2024.
  • For the discussion of changes from 2024 to 2023 and other financial information related to 2023, refer to Part II, Item 7.
  • "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2025.
  • Overview As of December 31, 2025, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins.
  • We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer.
  • Recent Developments Development Activity During the fourth quarter, Aethon 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.
  • Our agreement with Revenant covers 270,000 gross acres in which we currently control 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.
  • We 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, we entered into a 220,000 gross acre development agreement with Caturus, 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 our 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.
  • For additional information about our Shelby Trough development agreements, please read Part I, Items 1. and 2.
  • “Business and Properties—Our Assets—Shelby Trough Development Agreements”.
  • In the Permian Basin, 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 In the fourth quarter of 2025, we acquired $48.8 million of additional (primarily non-producing) mineral and royalty interests.
  • From September 2023 through December 2025, we have completed $239.5 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.
  • To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.
  • Oil prices decreased during the year ended December 31, 2025 compared to the same period in 2024, primarily due to increased global supply and uncertainty about the outlook for global economic growth and oil demand.
  • Supply growth from both OPEC+ and non-OPEC+ producers contributed to higher global inventories during the year, placing downward pressure on crude oil prices.
  • Natural gas prices increased during the year ended December 31, 2025 relative to the prior-year period.
  • Colder-than-normal weather during the first quarter increased heating demand and reduced storage levels, while higher demand for power generation during the summer months also contributed to higher natural gas prices.
  • In addition, continued growth in LNG export demand further strengthened market conditions.
  • In the fourth quarter of 2025, natural gas prices rose, driven by seasonal heating demand, continued LNG export demand, and relatively tight storage levels.
  • Given the dynamic nature of commodity markets, we cannot reasonably estimate how long current price levels or market conditions will persist.
  • The following table reflects commodity prices at the end of each quarter presented: 2025 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 57.26 $ 63.17 $ 66.30 $ 71.87 Henry Hub spot natural gas ($/MMBtu) 1 $ 4.00 $ 3.12 $ 3.26 $ 4.11 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
  • The following table shows the rig count at the end of each quarter presented: 2025 U.S.
  • Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 412 424 432 484 Natural gas 125 117 109 103 Other 9 8 6 5 Total 546 549 547 592 1 Source: Baker Hughes Incorporated Natural Gas Storage The majority of the production volumes attributable to our interests is derived from natural gas production.
  • The EIA forecasts that inventories will conclude the withdraw al season, which is the end of March 2026, at 1.8 Tcf, or 2% higher than the five-year average.
  • The EIA expects inventories will rise to 3.8 Tcf at the end of October 2026, which would be 5% higher than the five-year average.
  • The following table shows natural gas storage volumes by region at the end of each quarter presented: 2025 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 736 832 602 284 Midwest 865 972 688 364 Mountain 264 269 228 165 Pacific 307 302 287 202 South Central 1,203 1,186 1,148 758 Total 3,375 3,561 2,953 1,773 1 Source: EIA Natural Gas Exports Net natural gas exports avera ged 15.0 Bcf per day during 2025, a 26% incr ea se from the 2024 average.
  • The EIA forecasts average exports of 16.4 Bcf per day for the start of 2026, a 9% increase from 2025 levels.
  • LNG exports will increase as new LNG export projects begin operations in 2026.
  • Although the growth in LNG export capacity and global shipping has increased connectivity among certain markets, transportation remains infrastructure-dependent and subject to capacity constraints, and prices may continue to vary by region.

and 328 more.

Gone since FY2024

  • Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2024 and 2023.
  • For the discussion of changes from 2023 to 2022 and other financial information related to 2022, refer to Part II, Item 7.
  • "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2023 Annual Report on Form 10-K, which was filed with the SEC on February 20, 2024.
  • Overview As of December 31, 2024, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins.
  • We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured.
  • Recent Developments Development Activity Currently, EXCO Resources, Inc. is operating one rig and Aethon is operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.
  • During 2025, Aethon has already turned-to-sales (“TTS”) 11 gross (0.9 net) wells with early data showing better performance than the older offsets and initial rates primarily between 20 – 30 MMcf/d.
  • We expect Aethon to continue its development program under the amended JEAs with an estimated 17 gross (1.1 net) additional wells TTS during 2025.
  • In the Louisiana Haynesville during 2024, we entered into several Accelerated Drilling Agreements (“ADAs”) with large, well-capitalized operators.
  • Under these agreements, the operators will provide near term certainty and accelerated development on our high-interest areas in exchange for a reduced royalty burden.
  • During 2024, 2 gross (0.4 net) wells were TTS and we expect an additional 11 gross (0.6) net wells to TTS in 2025.
  • In the Permian Basin, a large producer is expected to begin development of over 37 gross (1.3 net) wells in Culberson County, Texas, which includes 8 gross wells to be TTS in the fourth quarter of 2025.
  • Farmout Agreements In September and December 2024, two of our farmout agreements covering non-operated working interests in San Augustine County terminated.
  • Consistent with our policy to minimize participation in working interests, we do not intend to step into the working interests associated with the terminated agreements.
  • Unless we agree otherwise with Aethon, we believe that Aethon, as operator and the party who has proposed the existing wells, has absorbed and will continue to absorb any non-consented interests.
  • To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.
  • Oil prices rose in early 2024 due to heightened geopolitical risks, including attacks on vessels in the Red Sea and elevated tensions in the region, but declined later in the year due to market oversupply concerns.
  • Natural gas prices decreased sharply in late 2023 and early 2024 due to surplus storage but increased in the second quarter of 2024 due to reduced drilling and production curtailments.
  • This upward trend continued into the third and fourth quarters, driven by high energy demand from extreme temperatures and increased LNG exports.
  • Given the dynamic nature of these events, along with the geopolitical conflicts in Ukraine and the Middle East, we cannot reasonably estimate how long these market conditions will persist.
  • The following table reflects commodity prices at the end of each quarter presented: 2024 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 72.44 $ 68.75 $ 82.83 $ 83.96 Henry Hub spot natural gas ($/MMBtu) 1 $ 3.40 $ 2.65 $ 2.42 $ 1.54 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
  • The following table shows the rig count at the end of each quarter presented: 2024 U.S.
  • Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 483 484 479 506 Natural gas 102 99 97 112 Other 4 4 5 3 Total 589 587 581 621 1 Source: Baker Hughes Incorporated Natural Gas Storage A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas.
  • The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025, at 1.9 Tcf, or 1% higher than the five-year average.
  • The EIA expects inventories will rise to 3.7 Tcf at the end of October 2025, which would be 2% lower than the five-year average.
  • The following table shows natural gas storage volumes by region at the end of each quarter presented: 2024 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 745 846 660 363 Midwest 914 1,012 779 510 Mountain 262 283 239 162 Pacific 295 294 282 227 South Central 1,197 1,113 1,174 996 Total 3,413 3,548 3,134 2,258 1 Source: EIA Natural Gas Exports Net natural gas exports averaged 12.0 Bcf per day during 2024, a 1% increase from the 2023 average.
  • The EIA forecasts average exports of 14.1 Bcf per day for the start of 2025, an 18% increase from 2024 levels.
  • LNG exports will increase as new LNG export projects begin operations in mid-2025.
  • Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price.
  • Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price.
  • Our open oil and natural gas derivative contracts as of December 31, 2024 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.
  • We are allowed, but not required, to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.
  • As of December 31, 2024, we had hedged 77% and 24% of our available oil and condensate hedge volumes and 82% and 69% of our available natural gas hedge volumes for 2025 and 2026, respectively.
  • We define 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, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any.
  • 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 U.S. as measures of our financial performance.
  • The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated: Year Ended December 31, 2024 2023 (in thousands) Net income (loss) $ 271,326 $ 422,549 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 45,196 45,683 Interest expense 3,109 2,754 Income tax expense (benefit) 509 320 Accretion of asset retirement obligations 1,298 1,042 Equity-based compensation 8,564 10,829 Unrealized (gain) loss on commodity derivative instruments 50,944 (8,394) (Gain) loss on sale of assets, net — (73) Adjusted EBITDA 380,946 474,710 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (4) (9) Cash interest expense (2,030) (1,715) Preferred unit distributions (29,466) (21,776) Distributable cash flow $ 349,446 $ 451,210 Results of Operations Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2024 2023 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,606 3,757 (151) (4.0) % Natural gas (MMcf) 1 62,984 64,647 (1,663) (2.6) % Equivalents (MBoe) 14,103 14,532 (429) (3.0) % Equivalents/day (MBoe) 38.5 39.8 (1.3) (3.3) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 74.61 $ 76.74 $ (2.13) (2.8) % Natural gas ($/Mcf) 1 2.51 3.10 (0.59) (19.0) % Equivalents ($/Boe) $ 30.27 $ 33.62 $ (3.35) (10.0) % Revenue: Oil and condensate sales $ 269,061 $ 288,296 $ (19,235) (6.7) % Natural gas and natural gas liquids sales 1 157,907 200,297 (42,390) (21.2) % Lease bonus and other income 12,461 12,506 (45) (0.4) % Revenue from contracts with customers 439,429 501,099 (61,670) (12.3) % Gain (loss) on commodity derivative instruments (5,730) 91,117 (96,847) (106.3) % Total revenue $ 433,699 $ 592,216 $ (158,517) (26.8) % Operating expenses: Lease operating expense $ 9,705 $ 11,386 $ (1,681) (14.8) % Production costs and ad valorem taxes 49,577 56,979 (7,402) (13.0) % Exploration expense 2,735 2,148 587 27.3 % Depreciation, depletion, and amortization 45,196 45,683 (487) (1.1) % General and administrative 52,082 51,455 627 1.2 % Other expense: Interest expense $ 3,109 $ 2,754 $ 355 12.9 % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators.
  • Revenue Total revenue for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023.
  • The decrease in total revenue from the corresponding period is due to lower oil and condensate sales, lower natural gas and NGL sales, and a loss on commodity derivative instruments in 2024 compared to a gain in 2023.
  • Oil and condensate sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes.
  • The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Eagle Ford play trends.

and 310 more.

Sentence-level comparison of Item 1A in the two most recent 10-Ks (FY2024 ↗, FY2025 ↗). A reworded sentence counts as one dropped and one added, so heavy edits read as low “kept”. Headings and page furniture are stripped; nothing is summarised by a model.

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