Black Stone Minerals, L.P.

Previous 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.

Current wording

At the end of the third quarter, Aethon Energy ("Aethon") was operating one rig on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough. Aethon’s development program remains on track, with 3 wells spud of the total 15 wells expected to be drilled in the current program year ending in June 2026. Aethon successfully turned to sales 2 gross (0.09 net) wells during the third quarter and has an inventory of 12 gross (0.78 net) wells from the previous program year that it expects to turn to sales during the fourth quarter of 2025 and early 2026.

Previous 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.

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. Recently, 2 gross (0.13 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 9.

Previous 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.

Current wording

In the Permian Basin, we continue to monitor activity including a large-scale development. A large operator has spud 34 gross (1.22 net) wells on our acreage in Culberson County, Texas. During the third quarter, 5 gross (0.18 net) wells were turned to sales. We anticipate 13 gross wells (0.47 net) to turn to sales in the fourth quarter of 2025, with the remaining 16 gross (0.57 net) wells expected in the first half of 2026.

Previous wording

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 wording

Oil prices decreased during the nine months ended September 30, 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 nine months ended September 30, 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. In the third quarter of 2025, natural gas pricing experienced a slight decline due to milder weather conditions lowering electricity demand.

Previous wording

A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas. 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 3.9 Tcf by the end of October 2025, which would be 3% 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") estimates that natural gas inventories concluded the injection season in October 2025 at 4.0 Tcf, which is 5% higher than the five-year average.

Previous 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.

Current wording

Net natural gas exports averaged 14.5 Bcf per day during the third quarter of 2025, a 22% increase from the 2024 average. The EIA forecasts average exports of 16.0 Bcf per day for the remainder of 2025 and 16.3 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 the remainder of 2025 and into 2026.

Previous 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.

Current wording

Total revenue for the quarter ended September 30, 2025 decreased compared to the quarter ended September 30, 2024. The decrease in total revenue in the third quarter of 2025 is primarily due to a decreased gain on our commodity derivative instruments compared to the corresponding prior period and a decrease in oil and condensate sales, which were partially offset by an increase in natural gas and NGL sales and lease bonus and other income.

Previous 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.

Current wording

Oil and condensate sales. Oil and condensate sales decreased for the quarter ended September 30, 2025 as compared to the corresponding period in 2024 primarily due to lower realized commodity prices, which were partially offset by increased production volumes. The increase in oil and condensate production was driven by higher 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 September 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 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.

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 third quarter of 2025, gains from our commodity derivative instruments decreased compared to the same period in 2024. For the three months ended September 30, 2025, we recognized $6.9 million of realized gains and $20.4 million of unrealized gains from our oil and natural gas commodity contracts, compared to $10.9 million of realized gains and $20.8 million of unrealized gains in the same period in 2024. The unrealized gains on our commodity contracts during the third quarter of 2025 were primarily driven by changes in the forward commodity price curves for natural gas. The unrealized gains for the same period in 2024 were primarily driven by changes in the forward commodity price curves for oil.

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 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.

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 third quarter of 2025 was higher than the same period in 2024. Leasing activity in the Permian Basin and Haynesville/Bossier plays made up the majority of lease bonus and other income for the third quarter of 2025, while the majority of the third quarter 2024 activity came from leasing activity in the Bakken/Three Forks.

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 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.

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 September 30, 2025, production costs and ad valorem taxes decreased as compared to the quarter ended September 30, 2024, primarily due to lower production taxes from decreased oil commodity prices and reduced natural gas production, 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 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.

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 September 30, 2025, exploration expenses decreased compared to the same period in 2024, primarily due to a decrease in seismic costs.

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 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.

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 September 30, 2025, general and administrative expenses slightly decreased as compared to the same period in 2024, primarily due to lower costs recognized under our short-term cash incentive plan.

Previous wording

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 wording

Total revenue for the nine months ended September 30, 2025 increased compared to the corresponding prior period. The increase in total revenue is primarily due to increases in natural gas and NGL sales and lease bonus and other income, and an increased gain on our commodity derivative instruments compared to the corresponding period. The overall increase was partially offset by a decrease in oil and condensate sales.

Previous wording

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 wording

Oil and condensate sales. Oil and condensate sales during the nine months ended September 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 and Austin Chalk. Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for the nine months ended September 30, 2025 and 2024, respectively.

Previous wording

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 wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 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 94% of our natural gas volumes for the nine months ended September 30, 2025 and 2024, respectively.

Previous wording

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 wording

Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2025, we recognized an increased gain from our commodity derivative instruments compared to the corresponding period in 2024. In the nine months ended September 30, 2025, we recognized $6.5 million of realized gains and $17.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $36.4 million of realized gains and $21.6 million of unrealized losses in the same period in 2024. Unrealized gains on our commodity contracts during the nine months ended September 30, 2025 were driven by changes in forward oil and natural gas price curves, compared to the corresponding period in 2024 when unrealized losses were driven by changes in forward natural gas price curves.

Previous wording

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 wording

Lease bonus and other income. Lease bonus and other income for the nine months ended September 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 nine months ended September 30, 2025, while a substantial portion of the activity in the corresponding period in 2024 came from 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.

Previous wording

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 wording

Lease operating expense. Lease operating expense increased for the nine months ended September 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. 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 wording

Production costs and ad valorem taxes. For the nine months ended September 30, 2025, production costs and ad valorem taxes decreased as compared to the nine months ended September 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

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 wording

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization decreased for the nine months ended September 30, 2025 as compared to the same period in 2024, primarily due to decreased production volumes.

Previous wording

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 wording

General and administrative. For the nine months ended September 30, 2025, general and administrative expenses slightly increased as compared to the same period in 2024, primarily due to increased salaries, equity-based compensation, and certain one-time personnel-related costs. This increase was partially offset by lower costs recognized under our short-term cash incentive plan and lower professional fees related to consulting costs for internal projects.

Previous wording

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 wording

Interest expense. Interest expense increased for the nine months ended September 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. 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.

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. On August 21, 2025, we entered into an agreement with the holders of the Series B cumulative converted preferred units under which we agreed not to exercise our redemption option and the holders agreed to vote in accordance with Board recommendations and comply with customary transfer and standstill restrictions through November 27, 2027, with the next redemption window opening on November 28, 2027. 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 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.

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 nine months ended September 30, 2025 as compared to the same period of 2024. The decrease was primarily due to reduced oil sales due to lower realized oil 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 due to higher realized natural gas prices in the nine months ended September 30, 2025 compared to the same period of 2024.

Previous 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.

Current wording

Investing Activities. Net cash used in investing activities in the nine months ended September 30, 2025 slightly decreased as compared to the same period of 2024. The decrease was primarily due to reduced amounts paid for acquisitions of oil and natural gas properties in the nine months ended September 30, 2025 compared to the same period of 2024. The overall decrease was partially offset by increased additions to oil and natural gas properties leasehold costs and lower proceeds from the sale of oil and natural gas properties.

Previous 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.

Current wording

Financing Activities. Net cash used in financing activities decreased for the nine months ended September 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 nine months ended September 30, 2025, compared to no net borrowings for the nine months ended September 30, 2024.

Previous 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.

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 $0.6 million has been invested in the nine months ended September 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 September 30, 2025, we have also spent $4.8 million acquiring leases in areas around our drilling programs.

Previous 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.

Current wording

During the nine months ended September 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 $65.7 million, including capitalized direct transaction costs. The consideration paid consisted of $58.3 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.

Previous wording

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 wording

We have two joint exploration agreements ("JEAs"; each, a "JEA") 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.

Previous wording

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 wording

Aethon expects to drill a total of 15 wells in the current program year that began in July 2025 and apply one of its banked wells toward its commitment. As of September 30, 2025, Aethon had spud three wells in the current program year and had an inventory of 12 wells drilled in the previous program year that are expected to be turned to sales during the fourth quarter of 2025 and early 2026.

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 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.

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. 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 November 2024 and April 2025 borrowing base redeterminations reaffirmed the borrowing base at $580.0 million. In October 2025, we amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and reduce the adjustment applied to secured overnight financing rate ("SOFR") loans. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was reaffirmed at $580.0 million and we elected to maintain cash commitments under the Credit Facility at $375.0 million. All existing banks in the lender syndicate elected to continue participating in the Credit Facility. No other significant terms were changed as part of the amendment. The next semi-annual redetermination is scheduled for April 2026.