Black Stone Minerals, L.P.
For the period ended Jun 30, 2026. Filed Aug 4, 2026.
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A company's report for each of its first three quarters. The financial statements are not audited. It shows how the business has moved since the last annual report, and what management says changed.
Jun 30, 2026 · Filed Aug 4, 2026
BSM$13.98-2.6%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-Q
Period ended 2026-03-31; filed 2026-05-05.
0001628280-26-030534
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2026-06-30; filed 2026-08-04.
0001628280-26-052686
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 144 previous paragraphs and 163 current paragraphs.
112 unchanged; 31 reworded; 13 added; 1 removed; 0 previous and 7 current paragraphs rearranged.
Tables are not compared: 8 previous and 9 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (13)
Current report
Operating and Other Expenses
Current report
Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025
Current report
The following table shows our production, revenues, pricing, and expenses for the periods presented:
Current report
Revenue
Current report
Total revenue for the six months ended June 30, 2026 decreased slightly compared to the corresponding prior period. The decrease in total revenue is primarily due to increased losses on our commodity derivative instruments partially offset by increased oil and condensate sales as well as higher lease bonus and other income.
Current report
Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2026 were flat compared to the corresponding prior period. Both commodity prices and production volumes remained relatively consistent between the comparable periods. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the six months ended June 30, 2026 and 2025, respectively.
Current report
Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2026, we recognized an increased loss from our commodity derivative instruments compared to the corresponding period in 2025. In the six months ended June 30, 2026, we recognized $21.0 million of realized losses and $16.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $0.5 million of realized losses and $2.7 million of unrealized losses in the same period in 2025. Unrealized losses on our commodity contracts during the six months ended June 30, 2026 were driven by changes in forward oil price curves, compared to the corresponding period in 2025 when unrealized losses were driven by changes in forward natural gas price curves.
Current report
Operating and Other Expenses
Current report
Exploration expense. For the six months ended June 30, 2026, exploration expense increased as compared to the six months ended June 30, 2025. The increase was primarily driven by purchases of seismic data and costs from proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough area.
Current report
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.
Current report
In May 2026, we entered into an amendment to the JEA that reduced the Program Year 1 drilling commitments to 4 wells following the well control incident in April 2026 affecting one of the two wells spud in the first quarter of 2026. The amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program.
Current report
1 Lateral-feet drilled in any AOI may be used to satisfy drilling commitments in other AOIs, except for the AOI 2 commitment in Program Year 2.
Current report
2 Revenant has the option to elect into the AOI 3 drilling commitment by June 30, 2028. If they do not make this election, the AOI 3 acreage and associated drilling commitment will be removed from the development program.
Removed paragraphs (1)
Previous report
Operating Expenses
Reworded paragraphs (31)
Previous wording
During the first quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating three rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas’s development program remains on track, with 4 wells spud in the first quarter of 2026 as part of the current program year ending June 30, 2026, an additional 4 wells expected in the second quarter 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. Adamas successfully turned to sales 7 gross (0.5 net) wells during the first quarter and expects to turn to sales 12 gross (1.2 net) wells during the remainder of 2026.
Current wording
At the end of the second quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating two rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas successfully turned to sales 4 gross (0.4 net) wells in July 2026. Adamas’s development program remains on track with the development agreements, with a total of 14 wells spud in the previous program year that ended on June 30, 2026. Of these wells, 6 gross (0.6 net) have turned to sales as of July 31, 2026, and 8 gross (0.7 net) are expected to turn to sales during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.
Previous wording
Our agreement with Revenant Energy ("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 spud two wells in the first quarter of 2026, one of which experienced a loss of well control incident in April 2026. We are currently assessing the potential impact of this incident on Revenant’s first program year development program and related well commitments.
Current wording
Our agreement with Revenant Energy ("Revenant") covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres. Under the original agreement, Revenant was 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 original 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. In May 2026, we entered into an amendment to the JEA that reduced the Program Year 1 drilling commitments to 4 wells following the well control incident in April 2026 affecting one of the two wells spud in the first quarter of 2026. The amendment also revised the gross lateral-foot commitments applicable to subsequent program years and released approximately 40,000 gross acres from the development program. Development activity continued during the second quarter of 2026, with Revenant spudding two additional wells.
Previous wording
In November 2025, we entered into a 220,000 gross acre development agreement with Caturus Energy, LLC ("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 the second half of 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.
Current wording
In November 2025, we entered into a 220,000 gross acre development agreement with Caturus Energy, LLC ("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 the second half of 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 development wells in 2026, Caturus is currently drilling a pilot well in Cherokee County, consistent with the terms of the agreement.
Previous wording
In the Permian Basin, Coterra Energy continues to develop our acreage in Culberson County, Texas. During the first quarter, 17 gross wells (0.6 net) were turned to sales. A separate development by another Permian operator of 25 gross (1.9 net) wells in the southern Delaware Basin is expected to come online in the second half of 2026 and first half of 2027.
Current wording
In the Permian Basin, Blue Arrow Operating is in progress on a development of 25 gross (1.9 net) wells in the southern Delaware Basin. Three wells were turned to sales during the quarter with the remaining expected to come online in the second half of 2026 and first half of 2027.
Previous wording
In the first quarter of 2026, we acquired $11.5 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through March 2026, we have completed $251.0 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.
Current wording
In the second quarter of 2026, consistent with our previously announced acquisition strategy, we acquired $37.2 million of additional (primarily non-producing) mineral and royalty interests. From September 2023 through June 2026, we have completed $299.7 million of mineral and royalty acquisitions, primarily in the expanding Shelby Trough area.
Previous wording
Oil prices increased during the three months ended March 31, 2026 compared to the same period in 2025, primarily due to the outbreak of conflict in Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices decreased during the three months ended March 31, 2026 relative to the prior-year period. Natural gas prices were elevated in January and early February 2026 due to colder-than-normal weather but declined over the remainder of the quarter as milder winter conditions across most of the U.S. persisted. Continued growth in natural gas production also contributed to downward pressure on prices during the quarter.
Current wording
Oil prices increased during the first half of 2026 compared to the same period in 2025, primarily due to the conflict with Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices were lower during the first half of 2026 relative to the prior-year period. Natural gas prices were elevated early in 2026 due to winter weather and tighter inventories but generally moderated during the remainder of the first six months as production growth increased market supplies. Recent price strength at the end of the second quarter was driven by rising electric power demand and increased U.S. liquefied natural gas ("LNG") export volumes.
Previous wording
The majority of the production volumes attributable to our interests is derived from natural gas production. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Current wording
The majority of the production volumes attributable to our interests are derived from natural gas production. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.
Previous wording
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 Tcf at the end of October 2026, which would be 6% higher than the five-year average.
Current wording
Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 Tcf at the end of October 2026, which would be 5% higher than the five-year average.
Previous wording
Net natural gas exports averaged 17.5 Bcf per day during the first quarter of 2026, a 16% increase from the 2025 average. The EIA forecasts average exports of 16.8 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that U.S. liquefied natural gas ("LNG") exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.
Current wording
Net natural gas exports averaged 17.2 Bcf per day during the second quarter of 2026, a 14% increase from the 2025 average. The EIA forecasts average exports of 17.3 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that LNG exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.
Previous wording
The prices we receive for oil, natural gas, and natural gas liquids ("NGLs") vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the U.S.
Current wording
The prices we receive for oil, natural gas, and natural gas liquids ("NGLs") vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All of our production is derived from properties located in the U.S.
Previous wording
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.
Current wording
We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.
Previous wording
We are allowed, but not required, to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of March 31, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027.
Current wording
The Credit Facility allows but does not require us to hedge, using swaps and collars with a term of no more than four years, up to 90% of our expected future volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48. As of June 30, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027.
Previous wording
Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three months ended March 31, 2025 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.
Current wording
Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three and six months ended June 30, 2025, 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.
Previous wording
Total revenue for the quarter ended March 31, 2026 increased compared to the quarter ended March 31, 2025. The increase in total revenue in the first quarter of 2026 is primarily due to higher oil and condensate sales and higher natural gas and NGL sales, which were partially offset by increased losses on our commodity derivative instruments and lower lease bonus and other income compared to the corresponding prior period.
Current wording
Total revenue for the quarter ended June 30, 2026 decreased compared to the quarter ended June 30, 2025. The decrease in total revenue in the second quarter of 2026 is primarily due to lower gains on our commodity derivative instruments and lower natural gas and NGL sales partially offset by increased oil and condensate sales as well as higher lease bonus and other income.
Previous wording
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2026 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods and increased production volumes. The increase in production was driven by higher royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% of our natural gas volumes for each of the quarters ended March 31, 2026 and 2025.
Current wording
Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended June 30, 2026 as compared to the corresponding prior period. The decrease between the comparative periods is due to lower realized commodity prices and slightly decreased production volumes. The decrease in production was driven by lower royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the quarters ended June 30, 2026 and 2025, respectively.
Previous wording
Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the first quarter of 2026, losses from our commodity derivative instruments increased compared to the same period in 2025. For the three months ended March 31, 2026, we recognized $12.2 million of realized losses and $52.3 million of unrealized losses from our oil and natural gas commodity contracts, compared to $3.6 million of realized losses and $52.4 million of unrealized losses in the same period in 2025. The unrealized losses on our commodity contracts during the first quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized losses for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.
Current wording
Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the second quarter of 2026, gains from our commodity derivative instruments decreased compared to the same period in 2025. For the three months ended June 30, 2026, we recognized $8.8 million of realized losses and $35.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $3.2 million of realized gains and $49.6 million of unrealized gains in the same period in 2025. The unrealized gains on our commodity contracts during the second quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized gains for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.
Previous wording
Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the first quarter of 2026 was lower than the same period in 2025. Leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development comprised the majority of lease bonus and other income for both the first quarter of 2026 and the first quarter of 2025. The surface use waivers covered mineral acreage in Mississippi for the first quarter of 2026 and Louisiana for the first quarter of 2025.
Current wording
Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the second quarter of 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play comprised the majority of lease bonus and other income for the second quarter of 2026, while the majority of lease bonus and other income in the second quarter of 2025 came from leasing activity in the Permian Basin and Bakken/Three Forks plays.
Previous wording
Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended March 31, 2026, production costs and ad valorem taxes decreased compared to the quarter ended March 31, 2025. The decrease was primarily due to $2.3 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions, as well as lower ad valorem tax estimates. The overall decrease was partially offset by higher production taxes due to increased production revenues and volumes.
Current wording
Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended June 30, 2026, production costs and ad valorem taxes decreased compared to the quarter ended June 30, 2025. The decrease was primarily due to $4.2 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.
Previous wording
Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. For the quarter ended March 31, 2026, exploration expenses decreased compared to the same period in 2025, primarily due to a decrease in seismic costs.
Current wording
Exploration expense. Exploration expense typically consists of dry-hole expenses, payments for delay rentals where the Partnership is the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. For the quarter ended June 30, 2026, exploration expenses increased compared to the same period in 2025, primarily due to higher expenditures for seismic costs incurred in connection with ongoing seismic shoots tied to our development programs.
Previous wording
Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended March 31, 2026 as compared to the same period in 2025 due to higher production volumes.
Current wording
Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended June 30, 2026 as compared to the same period in 2025 due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.
Previous wording
General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended March 31, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $1.1 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.
Current wording
General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended June 30, 2026, general and administrative expenses increasedas compared to the same period in 2025, primarily due to higher personnel costs, including $1.2 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.
Previous wording
Oil and condensate sales. Oil and condensate sales increased for the quarter ended March 31, 2026 as compared to the corresponding period in 2025 primarily due to increased production volumes, which were partially offset by slightly decreased realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty volumes in the Permian Basin and the Eagle Ford trends. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended March 31, 2026 and 2025.
Current wording
Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2026 increased compared to the corresponding prior period primarily due to higher production volumes and realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin and Bakken/Three Forks plays. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the six months ended June 30, 2026 and 2025.
Previous wording
Interest expense. Interest expense increased for the quarter ended March 31, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.
Current wording
Interest expense. Interest expense increased for the six months ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.
Previous wording
Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities decreased for the three months ended March 31, 2026 as compared to the same period of 2025. The decrease was primarily due to increased interest expense in the three months ended March 31, 2026, that resulted from higher average outstanding borrowings under our Credit Facility.
Current wording
Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities increased for the six months ended June 30, 2026 as compared to the same period of 2025. The increase was primarily driven by higher oil sales due to increased realized oil prices and production volumes in the six months ended June 30, 2026. The overall increase was partially offset by higher cash paid for the settlement of commodity derivatives.
Previous wording
Investing Activities. Net cash used in investing activities in the three months ended March 31, 2026 decreased as compared to the same period of 2025. The decrease was primarily due to reduced amounts paid for oil and natural gas properties leasehold costs in the three months ended March 31, 2026 compared to the same period of 2025. The overall decrease was partially offset by higher acquisitions of oil and natural gas properties.
Current wording
Investing Activities. Net cash used in investing activities in the six months ended June 30, 2026 increased as compared to the same period of 2025. The increase was primarily due to higher expenditures for acquisitions of oil and natural gas properties and leasehold costs in the six months ended June 30, 2026 compared to the same period of 2025.
Previous wording
Financing Activities. Net cash used in financing activities decreased for the three months ended March 31, 2026 as compared to the same period of 2025. The decrease was primarily driven by lower distributions paid to common unitholders for the three months ended March 31, 2026, compared to the same period of 2025. The overall decrease was partially offset by lower net borrowings under our Credit Facility.
Current wording
Financing Activities. Net cash used in financing activities remained consistent for the six months ended June 30, 2026 as compared to the same period of 2025. The decreased distributions paid to common unitholders for the six months ended June 30, 2026, compared to the same period of 2025 was partially offset by higher repayments of our Credit Facility.
Previous wording
Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.2 million during the three months ended March 31, 2026. We have also spent $0.2 million to acquire leases in areas around our drilling programs during the three months ended March 31, 2026.
Current wording
Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.3 million during the six months ended June 30, 2026. We also spent $6.3 million to acquire leases in areas around our drilling programs during the six months ended June 30, 2026.
Previous wording
During the three months ended March 31, 2026, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in East Texas from various sellers for cash consideration of $11.5 million, including capitalized direct transaction costs. The consideration paid was funded from borrowings under our Credit Facility and funds from operating activities. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.
Current wording
During the six months ended June 30, 2026, we acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $48.7 million, including capitalized direct transaction costs. The consideration paid consisted of $45.9 million in cash that was funded with borrowings under our Credit Facility and funds from operating activities, and $2.8 million in equity, that was funded through the issuance of common units based on the fair value of the common units issued on the acquisition dates. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.
Previous wording
Adamas 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 March 31, 2026, Adamas had spud 10 wells in the current program year and had a total of 10 banked wells.
Current wording
Adamas drilled a total of 14 wells during the program year that ended on June 30, 2026 and applied 2 of its 10 banked wells toward its commitment. As of July 31, 2026, 8 of those wells had not yet turned to sales and are expected to begin production during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.
Previous wording
In May 2025, we entered into a JEA with 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, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our undivided 35% working interest.
Current wording
In May 2025, we entered into a JEA with 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, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our retained undivided 35% working interest.
Previous wording
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:
Current wording
The table below summarizes the minimum gross lateral-foot drilling commitments under the amended agreement, following Program Year 1:
Rearranged current paragraphs (7)
Current report — wording carried from elsewhere
Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025 due to increased realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended June 30, 2026 and 2025.
Current report — wording carried from elsewhere
Interest expense. Interest expense increasedfor the quarter ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.
Current report — wording carried from elsewhere
1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes 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.
Current report — wording carried from elsewhere
Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play and proceeds from the surface use waivers on our mineral acreage supporting solar development in Mississippi made up the majority of lease bonus and other income for the six months ended June 30, 2026, while a substantial portion of the activity in the corresponding period in 2025 came from leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana.
Current report — wording carried from elsewhere
Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to a reduction in nonrecurring service-related expenses, including workovers.
Current report — wording carried from elsewhere
Production costs and ad valorem taxes. For the six months ended June 30, 2026, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2025, primarily due to $6.5 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.
Current report — wording carried from elsewhere
General and administrative. For the six months ended June 30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $2.3 million of cash compensation and $0.9 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.