Black Stone Minerals, L.P.
For the period ended Jun 30, 2025. Filed Aug 5, 2025.
View on SEC.govAbout this filing
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, 2025 · Filed Aug 5, 2025
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 2025-03-31; filed 2025-05-06.
0001628280-25-022559
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent report: 10-Q
Period ended 2025-06-30; filed 2025-08-05.
0001621434-25-000108
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 138 previous paragraphs and 156 current paragraphs.
104 unchanged; 23 reworded; 22 added; 11 removed; 0 previous and 7 current paragraphs rearranged.
Tables are not compared: 6 previous and 8 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 (22)
Current report
Revenant Joint Exploration Agreement and Farmout
Current report
In May 2025, we entered into a joint exploration agreement ("JEA") with Revenant Energy ("Revenant") covering approximately 270,000 gross acres across San Augustine, Nacogdoches, Angelina, Houston, and Trinity counties. The agreement includes annual well commitments that escalate over five years, from a minimum of 6 wells per year starting in 2026 increasing to a minimum of 25 wells per year for years 2030, and beyond, and require test wells in certain areas in order to continue operating across the full acreage. 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. For more information, see “—Liquidity and Capital Resources—Shelby Trough Development Agreements.”
Current report
Amendment to Aethon Joint Exploration Agreements
Current report
In May 2025, we entered into an amendment to the JEAs with Aethon in Angelina and San Augustine counties which reduces the contract area to approximately 210,000 gross acres. Under the terms of the amendment, Aethon released over 50,000 gross acres from the contract area, in exchange for reducing the annual well commitment to a total of 16 wells across both JEAs. The farmout agreements covering non-operated working interests under these JEAs have terminated, and Aethon is absorbing that working interest as part of the amendment. For more information, see “—Liquidity and Capital Resources—Shelby Trough Development Agreements.”
Current report
Oil prices decreased in the first half of 2025 compared to the same period in 2024, primarily due to weakening global demand amid, changes in trade policies, including imposition of tariffs and other import/export restrictions, and escalating trade tensions between the United States and China. The decline was further driven by an oversupplied market, as OPEC+ members unwound voluntary production cuts and non-OPEC+ producers increased output. Natural gas prices increased during the first half of 2025 relative to the prior-year period. Prices were supported by unusually cold weather in the first quarter of 2025, which drove higher heating demand and resulted in lower-than-average storage levels. Natural gas pricing was also supported by higher wholesale power pricing this summer compared to last summer.
Current report
Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024
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, 2025 increased compared to the corresponding prior period. The increase in total revenue is primarily due to a gain in natural gas and NGL sales and a reduced loss on our commodity derivative instruments compared to the corresponding prior period, which were partially offset by an decrease in oil and condensate sales.
Current report
Operating and Other Expenses
Current report
Production costs and ad valorem taxes. For the six months ended June 30, 2025, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2024, primarily due to lower production taxes from decreased oil commodity prices and reduced oil and natural gas production volumes, as well as lower ad valorem tax estimates.
Current report
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization decreased for the six months ended June 30, 2025 as compared to the same period in 2024, primarily due to decreased production volumes.
Current report
General and administrative. For the six months ended June 30, 2025, general and administrative expenses increased as compared to the same period in 2024, primarily due to increased cash and equity-based compensation. The increase in cash compensation was driven by increased salaries and certain one-time personnel-related costs. The increase in equity-based compensation was primarily due to a lower level of equity award forfeitures for the six months ended June 30, 2025 as compared to the same period in 2024.
Current report
Interest expense. Interest expense increased for the six months ended June 30, 2025 as compared to the corresponding period in 2024. The increase was due to higher average outstanding borrowings under our Credit Facility.
Current report
Acquisitions
Current report
We are party to a series of JEAs with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage in exchange for meeting minimum annual drilling commitments. Each JEA also includes a banked well provision, which allows operators that exceed their annual drilling commitments to carry forward excess wells to satisfy future obligations, subject to defined caps. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs.
Current report
Aethon Joint Exploration Agreements
Current report
We have two JEAs with Aethon covering portions of our acreage in San Augustine and Angelina counties, Texas. In May 2025, the parties entered into a letter agreement amending the JEAs. As amended, the agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas.
Current report
Aethon drilled a combined 22 wells under the two JEAs during the program years that ended in the second quarter of 2025. One well has been scheduled for plugging and will be replaced. As of June 30, 2025, 15 of those wells had not yet turned to sales and are expected to begin production during the remainder of 2025 and early 2026. Aethon expects to drill 15 wells in the next program year that begins in July 2025 and apply one of its 11 banked wells toward its commitment.
Current report
Revenant Joint Exploration Agreement
Current report
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 annual well commitments, 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 report
The well commitments under the agreement escalate over a five-year period, with the following table summarizing the well commitments across the three AOIs:
Removed paragraphs (11)
Previous report
Asset Exchanges
Previous report
During 2024 and the first quarter of 2025, we completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.
Previous report
In March 2025, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.
Previous report
In February 2025, we closed on a transaction with a third-party operator whereby we exchanged oil and natural gas leases covering certain acreage in East Texas. The Partnership acquired approximately 2,100 net leasehold acres in exchange for approximately 3,700 net leasehold acres.
Previous report
In July 2024, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.
Previous report
We have Joint Exploration Agreements ("JEAs") with Aethon Energy ("Aethon") to develop certain portions of our undeveloped acreage in San Augustine County and Angelina County in East Texas. The agreements provide for minimum annual well commitments by Aethon in exchange for reduced royalty rates and exclusive access to BSM's mineral and leasehold acreage in the contract areas. The Partnership's development agreement and related drilling commitments covering its San Augustine County acreage are independent of the development agreement and associated commitments covering Angelina County.
Previous report
If Aethon drills more than the minimum commitment wells in a given program year, Aethon may reduce its minimum well commitment in future program years by the number of excess wells, which we refer to as "banked" wells. Aethon's ability to apply banked wells to reduce its drilling commitments is capped at three or four wells each year, depending on the JEA. Upon the satisfaction of the current program year performance deadlines as described in the agreements, Aethon will have an inventory of one banked well in San Augustine and 10 banked wells in Angelina that will be available to satisfy its drilling commitments in future program years.
Previous report
The San Augustine JEA provides for a minimum of nine wells to be drilled in the current (third) program year ending in May 2025, with a minimum of 12 wells to be drilled in the fourth program year scheduled to commence in June 2025 and each program year thereafter. As of March 31, 2025, Aethon had drilled eight wells in the third program year under the San Augustine JEA, with one more well expected to be drilled by the end of the current program year in May 2025.
Previous report
The Angelina JEA provides for a minimum 15 wells to be drilled in the current (fourth) program year ending in June 2025 and, each program year thereafter. As of March 31, 2025, Aethon had drilled nine wells in the fourth program year under the Angelina JEA, with six more wells expected to be drilled by the end of the current program year in June 2025.
Previous report
Farmout Agreements
Previous report
We have entered into farmout arrangements designed to reduce our working interest capital expenditures and thereby significantly lower our capital spending other than for mineral and royalty interest acquisitions. Under these agreements, we conveyed our rights to participate in certain non-operated working interest opportunities to external capital providers while retaining value from these interests in the form of additional royalty income or retained economic interests. These farmout arrangements cover a portion of our share of working interests under active development by Aethon in San Augustine and Angelina County in East Texas.
Reworded paragraphs (23)
Previous wording
•the level of drilling activity by our operators particularly in areas such as the Shelby Trough where we have concentrated acreage positions;
Current wording
•the level of drilling activity by our operators particularly in areas such as the Haynesville where we have concentrated acreage positions;
Previous wording
At the end of the first quarter, EXCO Resources Inc. was operating one rig, and Aethon was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. During the quarter, Aethon successfully turned to sales 11 gross (0.7 net) wells, with the majority of the wells showing improved results compared to older offsets. Aethon’s development program remains on track, with an estimated 17 gross (1.0 net) additional wells expected to turn to sales during the remainder of 2025.
Current wording
At the end of the second quarter, Aethon Energy ("Aethon") was operating two rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. During the quarter, Aethon successfully turned to sales 2 gross (0.10 net) wells. Aethon’s development program remains on track with the development agreements, with a total of 22 wells spud in the previous program years that ended in the second quarter of 2025. Of these wells, 7 gross (0.42 net) have turned to sales and 15 gross (0.93 net) are expected to turn to sales during the remainder of 2025 and early 2026. EXCO Resources Inc. also remains active on our acreage, completing 2 gross (0.08 net) wells in early June, and recently spud 2 gross (0.08 net) wells in July.
Previous wording
In the Louisiana Haynesville, development continued under our Accelerated Drilling Agreements (“ADAs”). These agreements provide greater near-term certainty by accelerating development and associated revenue in our high-interest areas in exchange for a modest reduction in royalty burden. During the first quarter, two gross (0.2 net) wells in De Soto Parish were turned to sales under our ADAs.
Current wording
In the Louisiana Haynesville, development continued under our Accelerated Drilling Agreements (“ADAs”). These agreements incentivize operators to accelerate development in our high-interest areas in exchange for a modest reduction in royalty burden, allowing us to capture near-term revenue and reduce uncertainty about where the locations sit in the operator's development plan. During the second quarter, 3 gross (0.09 net) wells in De Soto and Sabine Parishes were turned to sales under our ADAs. This brings the total well count under the ADA program to seven. We expect another 2 gross (0.13 net) wells to be turned to sales during the third quarter of 2025.
Previous wording
In the Permian Basin, we continue to monitor several large-scale development projects expected to generate meaningful liquids volumes in 2025 and beyond. As previously disclosed, a large operator has planned more than 35 gross (1.25 net) wells in Culberson County, Texas. To date, 24 of these wells have been spud. We anticipate nine gross wells to turn to sales in the fourth quarter of 2025, with the remainder expected in the first half of 2026.
Current wording
In the Permian Basin, we continue to monitor activity including a large-scale development. A large operator has planned more than 34 gross (1.20 net) wells in Culberson County, Texas. To date, 30 of these wells have been spud. We anticipate 22 gross wells to turn to sales in the second half of 2025, with the remainder expected in the first half of 2026.
Previous wording
Oil prices decreased during the first quarter of 2025 due to concerns arising from changes in trade policies, including the imposition of tariffs and other import/export restrictions, and their resulting consequences, which raised fears of a global economic slowdown and weakened expectations for oil demand growth. In April 2025, OPEC+ announced plans to accelerate production increases starting in May that were originally set for July, causing oil prices to continue to decrease. Natural gas prices rose in the first quarter of 2025 due to unusually cold weather in January and February, leading to higher consumption for heating and lower than expected storage levels. In addition, two new LNG export facilities began operations during the quarter, driving additional demand and higher prices. Given the dynamic nature of these events, including uncertainty regarding changes in trade policies and their resulting consequences, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.
Current wording
Given the dynamic nature of these events, including uncertainty regarding changes in trade policies and their resulting consequences, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.
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 3.7 Tcf by the end of October 2025, which would be 3% lower 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 3.9 Tcf by the end of October 2025, which would be 3% higher than the five-year average.
Previous wording
Net natural gas exports averaged 14.4 Bcf per day during the first quarter of 2025, a 21% increase from the 2024 average. The EIA forecasts average exports of 15.5 Bcf per day for the remainder of 2025 and 16.4 Bcf per day for 2026. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations during 2025.
Current wording
Net natural gas exports averaged 14.2 Bcf per day during the first half of 2025, a 19% increase from the 2024 average. The EIA forecasts average exports of 15.1 Bcf per day for the remainder of 2025 and 16.0 Bcf per day for 2026. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations during 2025 and 2026.
Previous wording
Total revenue for the quarter ended March 31, 2025 decreased compared to the quarter ended March 31, 2024. The decrease is primarily due to an increase in unrealized losses from our commodity derivative instruments and a decrease in oil, and condensate sales, compared to the corresponding prior period. The decreased in revenue was partially offset by an increase in natural gas and NGL sales.
Current wording
Total revenue for the quarter ended June 30, 2025 increased compared to the quarter ended June 30, 2024. The increase in total revenue in the second quarter of 2025 is primarily due to a gain on our commodity derivative instruments compared to a loss in the corresponding prior period and an increase in natural gas and NGL sales, which were partially offset by a decrease in oil and condensate sales.
Previous wording
Oil and condensate sales. Oil and condensate sales decreased for the quarter ended March 31, 2025 as compared to the corresponding period in 2024 primarily due to lower production volumes and realized commodity prices. The decrease in oil and condensate production was driven by reduced mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 94% of total oil and condensate volumes for quarters ended March 31, 2025 and 2024, respectively.
Current wording
Oil and condensate sales. Oil and condensate sales decreased for the quarter ended June 30, 2025 as compared to the corresponding period in 2024 primarily due to lower production volumes and realized commodity prices. The decrease in oil and condensate production was driven by reduced mineral and royalty volumes in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for quarters ended June 30, 2025 and 2024, respectively.
Previous wording
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2025 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods partially offset by a reduction in production volumes. The decrease in natural gas and NGL production was driven by lower mineral and royalty production in the Haynesville/Bossier, Fayetteville, and Austin Chalk play trends. Mineral and royalty interest production accounted for 97% and 95% of our natural gas volumes for the quarters ended March 31, 2025 and 2024, respectively.
Current wording
Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended June 30, 2025 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods partially offset by a decrease in production volumes. The decrease in production was driven by reduced royalty interest volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 96% and 94% of our natural gas volumes for the quarters ended June 30, 2025 and 2024, 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 2025, we recognized an increase in losses from our commodity derivative instruments compared to the same period in 2024. For the three months ended March 31, 2025, we recognized $3.6 million of realized losses and $52.4 million of unrealized losses from our oil and natural gas commodity contracts, compared to $13.8 million of realized gains and $25.1 million of unrealized losses in the same period in 2024. The unrealized losses on our commodity contracts during the first quarter of 2025 and the unrealized losses in the corresponding period in 2024 were primarily driven by changes in the forward commodity price curves for oil and 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 2025, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2024. For the three months ended June 30, 2025, we recognized $3.2 million of realized gains and $49.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $11.8 million of realized gains and $17.4 million of unrealized losses in the same period in 2024. The unrealized gains on our commodity contracts during the second quarter of 2025 were primarily driven by changes in the forward commodity price curves for oil. The unrealized losses for the same period in 2024 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 2025 was higher than the same period in 2024. Leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana made up the majority of lease bonus and other income for the first quarter of 2025. The majority of lease bonus and other income for the first quarter of 2024 came from leasing activity in the Austin Chalk and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas.
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 2025 was consistent with the same period in 2024. Leasing activity in the Permian Basin and Bakken/Three Forks plays made up the majority of lease bonus and other income for the second quarter of 2025, while the majority of the second quarter 2024 activity came from leasing activity in the Permian Basin.
Previous wording
Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2025 as compared to the same period in 2024, primarily due to lower nonrecurring service-related expenses, including workovers.
Current wording
Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense increased for the quarter ended June 30, 2025 as compared to the same period in 2024, primarily due to increased nonrecurring service-related expenses, including workovers.
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, 2025, production costs and ad valorem taxes decreased as compared to the quarter ended March 31, 2024, primarily due to lower production taxes stemming from lower oil and condensate commodity prices and decreased production 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, 2025, production costs and ad valorem taxes decreased as compared to the quarter ended June 30, 2024, primarily due to lower production taxes from decreased oil commodity prices and reduced oil and natural gas production volumes, as well as lower ad valorem tax estimates.
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, 2025, exploration expenses increased compared to the same period in 2024, primarily due to a one-time $4.0 million purchase of seismic data and additional costs related to seismic data acquisition projects. These seismic initiatives aim to further bolster our subsurface evaluation of the expanded Shelby Trough area. Exploration expenses were minimal in the first quarter of 2024.
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, 2025, exploration expenses increased compared to the same period in 2024, primarily due to additional costs related to seismic data acquisition projects associated with existing and future development programs in the expanded Shelby Trough area. Exploration expenses were minimal in the second quarter of 2024.
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, 2025, general and administrative expenses increased as compared to the same period in 2024, primarily due to increased cash and equity-based compensation. The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during the quarter ended March 31, 2025 compared to minimal price changes in the corresponding period in 2024.
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, 2025, general and administrative expenses slightly increased as compared to the same period in 2024, primarily due to higher cash compensation driven by increased salaries and certain one-time personnel-related costs.
Previous wording
Interest expense. Interest expense in the first quarter of 2025 increased as compared to the corresponding period in 2024, due to increased borrowings under our Credit Facility. Average outstanding borrowings during the first quarter of 2025 were higher than the first quarter of 2024 due to funding acquisitions in 2025 and 2024.
Current wording
Interest expense. Interest expense increased for the quarter ended June 30, 2025 as compared to the corresponding period in 2024. The increase was due to higher average outstanding borrowings under our Credit Facility.
Previous wording
Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business. On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date"). The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum. We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value. See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.
Current wording
Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility, and for investing in our business. On November 28, 2023 the distribution rate for the Series B cumulative convertible preferred units was adjusted to 9.8% and will be readjusted every two years thereafter (each, a "Readjustment Date"). The rate set on each Readjustment Date is equal to the greater of (i) the distribution rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum. We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90 day period beginning on each Readjustment Date at a redemption price of $20.39 per Series B cumulative convertible preferred unit, which is equal to par value. Depending on market conditions among other factors, we may use funds from the future issuance of common units or other equity securities or debt to redeem some or all of the preferred units. See "Note 9 - Preferred Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information.
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, 2025 as compared to the same period of 2024. The decrease was primarily due to reduced oil and condensate sales due to lower realized commodity prices and production, changes in operating assets and liabilities due to the timing of payments, and net cash paid on the settlement of commodity derivatives in the three months ended March 31, 2025 compared to net cash received for the same period of 2024. The overall decrease in cash flows from operations was partially offset by increased natural gas and NGL sales resulting from higher realized commodity prices.
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 decreased for the six months ended June 30, 2025 as compared to the same period of 2024. The decrease was primarily due to reduced oil sales due to lower realized commodity prices and production, lower amounts of cash received from the settlement of commodity derivatives, and changes in operating assets and liabilities due to the timing of payments. The overall decrease was partially offset by higher natural gas and NGL sales in the six months ended June 30, 2025 compared to the same period of 2024.
Previous wording
Investing Activities. Net cash used in investing activities in the three months ended March 31, 2025 decreased as compared to the same period of 2024. The decrease was primarily due to reduced acquisitions of oil and natural gas properties in the three months ended March 31, 2025 compared to the same period of 2024.
Current wording
Investing Activities. Net cash used in investing activities in the six months ended June 30, 2025 decreased as compared to the same period of 2024. The decrease was primarily due to reduced acquisitions of oil and natural gas properties in the six months ended June 30, 2025 compared to the same period of 2024.
Previous wording
Financing Activities. Cash flows used in financing activities decreased for the three months ended March 31, 2025 as compared to the same period of 2024. The decrease was primarily due to lower distributions paid to unitholders and net borrowings on our Credit Facility for the three months ended March 31, 2025.
Current wording
Financing Activities. Cash flows used in financing activities decreased for the six months ended June 30, 2025 as compared to the same period of 2024. The decrease was primarily driven by lower distributions paid to unitholders and by net borrowings on our Credit Facility for the six months ended June 30, 2025, compared to no net borrowings for the six months ended June 30, 2024.
Previous wording
Our 2025 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, of which $0.1 million has been invested in the three months ended March 31, 2025. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest. Through March 31, 2025, we have also spent $3.0 million acquiring leases on acreage utilized for our drilling programs.
Current wording
Our 2025 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.3 million has been invested in the six months ended June 30, 2025. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest. Through June 30, 2025, we have also spent $4.6 million acquiring leases in areas around our drilling programs.
Previous wording
During the three months ended March 31, 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $14.2 million, including capitalized direct transaction costs. The consideration paid consisted of $10.3 million in cash that was funded from operating activities and $3.9 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. These acquisitions were considered asset acquisitions and were primarily located in the Gulf Coast land region. Our current 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, 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $45.4 million, including capitalized direct transaction costs. The consideration paid consisted of $38.0 million in cash that was funded from operating activities and $7.4 million in equity that was funded through the issuance of common units of the Partnership based on the fair values of the common units issued on the acquisition dates. These acquisitions were considered asset acquisitions and were primarily located in the Gulf Coast land region. Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.
Rearranged current paragraphs (7)
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
Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2025 decreased compared to the corresponding prior period primarily due to lower production volumes and realized commodity prices. The decrease in oil and condensate production was driven by reduced mineral and royalty production in the Permian Basin. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 94% of total oil and condensate volumes for the six months ended June 30, 2025 and 2024, respectively.
Current report — wording carried from elsewhere
Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2025 increased compared to the corresponding prior period due to higher realized commodity prices partially offset by lower production volumes. The decrease in production volumes was driven by a reduction in royalty interest production volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 96% and 95% of our natural gas volumes for the six months ended June 30, 2025 and 2024, respectively.
Current report — wording carried from elsewhere
Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2025, we recognized a reduced loss from our commodity derivative instruments compared to the corresponding period in 2024. In the six months ended June 30, 2025, we recognized $0.5 million of realized losses and $2.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $25.6 million of realized gains and $42.5 million of unrealized losses in the same period in 2024. Unrealized losses on our commodity contracts during the six months ended June 30, 2025 were primarily driven by changes in forward natural gas price curves, compared to the corresponding period in 2024 when unrealized losses were driven by changes in forward oil and natural gas price curves.
Current report — wording carried from elsewhere
Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2025 was higher than the same period in 2024. Leasing activity in the Permian Basin and proceeds from the surface use waivers on our mineral acreage supporting solar development in Louisiana made up the majority of lease bonus and other income for the six months ended June 30, 2025, while a substantial portion of the activity in the corresponding period in 2024 came from leasing activity in the Permian Basin and the Austin Chalk play trend and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas.
Current report — wording carried from elsewhere
Lease operating expense. Lease operating expense slightly increased for the six months ended June 30, 2025 as compared to the same period in 2024, primarily due to increased nonrecurring service-related expenses, including workovers.
Current report — wording carried from elsewhere
Exploration expense. For the six months ended June 30, 2025, exploration expense increased as compared to the six months ended June 30, 2024, primarily due to a one-time $4.0 million purchase of seismic data and additional costs related to seismic data acquisition projects.