Black Stone Minerals, L.P.
For the period ended Mar 31, 2025. Filed May 6, 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.
Mar 31, 2025 · Filed May 6, 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 2024-09-30; filed 2024-11-05.
0001628280-24-045189
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of OperationsCurrent 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 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 140 previous paragraphs and 138 current paragraphs.
99 unchanged; 20 reworded; 18 added; 16 removed; 5 previous and 1 current paragraphs rearranged.
Tables are not compared: 7 previous and 6 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 (18)
Current report
•domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products;
Current report
Development Activity
Current report
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 report
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 report
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 report
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 report
2 Not meaningful.
Current report
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 report
Asset Exchanges
Current report
During 2024 and the first quarter of 2025, we completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.
Current 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.
Current report
Shelby Trough Development Agreements
Current 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.
Current 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.
Current 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.
Current 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.
Current report
Farmout Agreements
Current 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.
Removed paragraphs (16)
Previous report
Shelby Trough Development Update
Previous report
In September 2024, we entered into letter agreements with Aethon Energy ("Aethon") to amend the Joint Exploration Agreements ("JEAs") in San Augustine and Angelina counties. In those agreements, the parties agreed to revise the current program year drill schedules under each JEA, to extend the respective program years by nine months, and to withdraw the invocation of the time-out provisions. Aethon also released its rights under 25,000 acres from the parties' area of mutual interest defined in the original JEAs. Upon the satisfaction of the current program year performance deadlines as described in the letter agreements, Aethon will have an inventory of ten banked wells in Angelina and one banked well in San Augustine.
Previous report
While oil inventories continued to decline in the third quarter of 2024, oil prices decreased during the period because of offsetting concerns that the market would continue to be oversupplied in 2025 without additional growth in demand. OPEC+ members' decision to delay production increases until December 2024 is expected to lead to further reductions in global inventories and is reflective of the lingering impact of rising global inventories experienced in 2023. Heightened geopolitical risk related to continued conflict in the Middle East has increased the possibility for future supply disruptions and price volatility. Natural gas prices decreased sharply in the fourth quarter of 2023 and the first quarter of 2024 as a result of a large surplus of storage inventory. Less natural gas-directed drilling and production curtailments led to increased natural gas prices in the second quarter of 2024 which continued to recover in the third quarter of 2024 due to hot summer temperatures and the related increase in U.S. electricity demand across all sectors. An increase in LNG exports with the addition of capacity further added to natural gas price increases in the third quarter of 2024. Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine and the Middle East, 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 report
Total revenue for the quarter ended September 30, 2024 increased compared to the quarter ended September 30, 2023. The increase in total revenue in the third quarter of 2024 is primarily due to a gain on our commodity derivative instruments compared to a loss in the corresponding prior period, which were partially offset by a decrease in natural gas, NGL, oil, and condensate sales.
Previous report
Interest expense. Interest expense in the third quarter of 2024 increased as compared to the corresponding period in 2023, with minimal average outstanding borrowings under our Credit Facility during each period. Interest expense for both periods primarily consisted of commitment fees and amortization of debt issuance costs.
Previous report
Nine Months Ended September 30, 2024 Compared to Nine Months Ended September 30, 2023
Previous report
The following table shows our production, revenues, pricing, and expenses for the periods presented:
Previous report
Revenue
Previous report
Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2024 slightly increased compared to the corresponding prior period primarily due to higher production volumes. Our mineral and royalty interest oil and condensate volumes accounted for 95% and 94% of total oil and condensate volumes for the nine months ended September 30, 2024 and 2023, respectively.
Previous report
Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2024 decreased compared to the corresponding prior period due to lower realized commodity prices. Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the nine months ended September 30, 2024 and 2023, respectively.
Previous report
Operating and Other Expenses
Previous report
Exploration expense. For the nine months ended September 30, 2024 exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.
Previous report
Depreciation, depletion, and amortization. Depreciation, depletion, and amortization slightly increased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to increased production volumes.
Previous report
General and administrative. For the nine months ended September 30, 2024, general and administrative expenses increased as compared to the same period in 2023, primarily due to higher professional costs related to outside legal fees, consulting costs for internal projects, and cash compensation, partially offset by a decrease in equity-based compensation. The increase in cash compensation was driven by increases in salaries and costs recognized under our short-term cash incentive plan. The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the nine months ended September 30, 2024 compared to upward movements in the corresponding prior period.
Previous report
Interest expense. Interest expense was lower in the nine months ended September 30, 2024 than in the prior period primarily due to lower average outstanding borrowings under our Credit Facility.
Previous report
Asset Exchange
Reworded paragraphs (20)
Previous wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2023 ("2023 Annual Report on Form 10-K"). This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Current wording
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our unaudited condensed consolidated financial statements and notes thereto presented in this Quarterly Report on Form 10-Q, as well as our audited consolidated financial statements and notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2024 ("2024 Annual Report on Form 10-K"). This discussion and analysis contains forward-looking statements that involve risks, uncertainties, and assumptions. Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part II, Item 1A. Risk Factors.”
Previous wording
As of September 30, 2024, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 68,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
Current wording
As of March 31, 2025, our mineral and royalty interests were located in 41 states in the continental United States, including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells. We also own non-operated working interests, a significant portion of which are on our positions where we also have a mineral and royalty interest. We recognize oil and natural gas revenue from our mineral and royalty and non-operated working interests in producing wells when control of the oil and natural gas produced is transferred to the customer and collectability of the sales price is reasonably assured. Our other sources of revenue include mineral lease bonus and delay rentals, which are recognized as revenue according to the terms of the lease agreements.
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") estimates that natural gas inventories concluded the injection season in October 2024 at 3.9 Tcf, which is 4% 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 3.7 Tcf by the end of October 2025, which would be 3% lower than the five-year average.
Previous wording
Net natural gas exports averaged 11.5 Bcf per day during the third quarter of 2024, a 3% decrease from the 2023 average. The EIA forecasts average exports of 13.2 Bcf per day for the remainder of 2024 and 13.8 Bcf per day for 2025. The EIA forecast reflects assumptions that U.S. LNG exports will increase as LNG export projects come on line in late 2024 and mid-2025.
Current 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.
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 September 30, 2024, we had hedged 75% and 71% of our available oil and condensate hedge volumes for 2024 and 2025, respectively. As of September 30, 2024, we had also hedged 77% and 79% of our available natural gas hedge volumes for 2024 and 2025, respectively.
Current 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, 2025, we have hedged a portion of our expected future volumes for the remainder of 2025 and 2026.
Previous wording
Total revenue for the nine months ended September 30, 2024 decreased compared to the corresponding prior period. The decrease in total revenue is primarily due to a reduced gain on our commodity derivative instruments compared to the gain in the corresponding prior period and a decrease in natural gas and NGL sales, which were partially offset by an increase in oil and condensate sales.
Current 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.
Previous wording
Oil and condensate sales. Oil and condensate sales decreased for the quarter ended September 30, 2024 as compared to the corresponding period in 2023 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 95% and 96% of total oil and condensate volumes for quarters ended September 30, 2024 and 2023, respectively.
Current 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.
Previous wording
Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended September 30, 2024 as compared to the corresponding prior period. The decrease was due to lower realized commodity prices between the comparative periods and 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 play trend. Mineral and royalty interest production accounted for 94% and 94% of our natural gas volumes for the quarters ended September 30, 2024 and 2023, respectively.
Current 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.
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 third quarter of 2024, we recognized a gain from our commodity derivative instruments compared to a loss in the same period in 2023. For the three months ended September 30, 2024, we recognized $10.9 million of realized gains and $20.8 million of unrealized gains from our oil and natural gas commodity contracts, compared to $24.2 million of realized gains and $51.1 million of unrealized losses in the same period in 2023. The unrealized gains on our commodity contracts during the third quarters of 2024 and the unrealized losses in the corresponding period in 2023 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 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.
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 third quarter of 2024 was lower than the same period in 2023. Leasing activity in the Bakken/Three Forks made up the majority of lease bonus and other income for the third quarter of 2024, while the majority of the third quarter 2023 activity came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.
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 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.
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 September 30, 2024, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2023, primarily due to lower production taxes stemming from lower 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 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.
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 September 30, 2024, exploration expenses increased compared to the same period in 2023, primarily due to an increase in seismic purchases and delay rentals.
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 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.
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 September 30, 2024, general and administrative expenses decreased as compared to the same period in 2023, primarily due to a decrease in consulting costs and equity-based compensation, partially offset by an increase in salaries. The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during the quarter ended September 30, 2024 compared to upward movements in the corresponding prior period.
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 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.
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 nine months ended September 30, 2024 as compared to the same period of 2023. The decrease was primarily due to lower natural gas and NGL sales stemming from lower realized commodity prices and a reduction in cash received on the settlement of commodity derivatives in the nine months ended September 30, 2024 compared to the same period of 2023.
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 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.
Previous wording
Investing Activities. Net cash used in investing activities in the nine months ended September 30, 2024 increased as compared to the same period of 2023. The increase was primarily due to acquisitions of oil and natural gas properties in the nine months ended September 30, 2024 as compared to minimal acquisition activity in the corresponding prior period.
Current 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.
Previous wording
Financing Activities. Cash flows used in financing activities decreased for the nine months ended September 30, 2024 as compared to the same period of 2023. The decrease was primarily due to lower distributions paid to unitholders and no net repayments on our Credit Facility for the nine months ended September 30, 2024 compared to net repayments for the nine months ended September 30, 2023.
Current 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.
Previous wording
Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million, net of farmout reimbursements, of which $0.7 million has been invested in the nine months ended September 30, 2024. 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 September 30, 2024, we have also spent $1.8 million acquiring leases in areas around 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, 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.
Previous wording
During the nine months ended September 30, 2024, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $65.2 million, including capitalized direct transaction costs. The consideration paid consisted of $64.2 million in cash that was funded from operating activities and $1.0 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 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.
Previous wording
In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received 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.
Current wording
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 wording
We maintain a senior secured revolving credit agreement, as amended, (the "Credit Facility"). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million. The subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2025.
Current wording
We maintain a senior secured revolving credit agreement, as amended, (the "Credit Facility"). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. The April 2024, November 2024, and April 2025 borrowing base redeterminations reaffirmed the borrowing base at $580.0 million. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for October 2025.
Rearranged current paragraphs (1)
Current report — wording carried from elsewhere
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.
Rearranged previous paragraphs (5)
Previous report — wording carried 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.
Previous report — wording carried elsewhere
Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2024, we recognized a reduced gain from our commodity derivative instruments as compared to the gain recognized for the same period in 2023. In the nine months ended September 30, 2024, we recognized $36.4 million of realized gains and $21.6 million of unrealized losses from our oil and natural gas commodity contracts, compared to $65.7 million of realized gains and $29.0 million of unrealized losses in the same period in 2023. The unrealized losses on our commodity contracts during the nine months ended September 30, 2024 and the corresponding period in 2023 were primarily driven by changes in the forward commodity price curves for oil and natural gas.
Previous report — wording carried elsewhere
Lease bonus and other income. Lease bonus and other income for the nine months ended September 30, 2024 was higher than the same period in 2023. Leasing activity in the Permian Basin, Bakken/Three Forks, and the Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development in Texas composed the majority of lease bonus and other income for the nine months ended September 30, 2024, while a substantial portion of the activity in the corresponding prior period came from leasing activity in the Bakken/Three Forks and Haynesville/Bossier plays.
Previous report — wording carried elsewhere
Lease operating expense. Lease operating expense decreased for the nine months ended September 30, 2024 as compared to the same period in 2023, primarily due to lower nonrecurring service-related expenses, including workovers.
Previous report — wording carried elsewhere
Production costs and ad valorem taxes. For the nine months ended September 30, 2024, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2023, primarily due to a decrease in production taxes from lower oil and natural gas commodity prices.