Black Stone Minerals, L.P.

Previous wording

At the end of the second quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating two rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas successfully turned to sales 4 gross (0.4 net) wells in July 2026. Adamas’s development program remains on track with the development agreements, with a total of 14 wells spud in the previous program year that ended on June 30, 2026. Of these wells, 6 gross (0.6 net) have turned to sales as of July 31, 2026, and 8 gross (0.7 net) are expected to turn to sales during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.

Current wording

As of the end of the third quarter, Adamas Energy ("Adamas") was operating two rigs on our Angelina and San Augustine acreage in the Shelby Trough. During the third quarter, Adamas successfully turned to sales 7 gross (0.7 net) wells. Adamas’s development program remains on track with the development agreements, with a total of 14 wells spud in the previous program year that ended on June 30, 2026. Of these wells, 9 gross (0.9 net) have turned to sales as of September 30, 2026, and 4 gross (0.4 net) are expected to turn to sales during the fourth quarter of 2026, with the remaining well under further evaluation. As of September 30, 2026, Adamas spud 6 of the total 17 wells expected to be drilled in the current program year ending on June 30, 2027.

Previous wording

In November 2025, we entered into a 220,000 gross acre development agreement with Caturus Energy, LLC ("Caturus"), which aims to push the Shelby Trough westward towards the Western Haynesville. Activity will begin with approximately 2 gross (0.2 net) wells in the second half of 2026 and ramp to approximately 12 gross (0.8 net) wells annually by 2031, supported by minimum annual lateral-foot requirements, all net to our interest. In addition to the 2 gross development wells in 2026, Caturus is currently drilling a pilot well in Cherokee County, consistent with the terms of the agreement.

Current wording

In November 2025, we entered into a 220,000 gross acre development agreement with an affiliate of Caturus Energy, LLC ("Caturus") covering acreage primarily in Angelina, Cherokee, Houston, and Nacogdoches counties in Texas, which aims to push the Shelby Trough westward toward the Western Haynesville. Development activity under the original agreement is underway. Caturus drilled a pilot well in Cherokee County in the third quarter of 2026 and, in October 2026, spud its first 2 development wells, which are expected to begin production in the first half of 2027.

Previous wording

In the Permian Basin, Blue Arrow Operating is in progress on a development of 25 gross (1.9 net) wells in the southern Delaware Basin. Three wells were turned to sales during the quarter with the remaining expected to come online in the second half of 2026 and first half of 2027.

Current wording

In the Permian Basin, Blue Arrow Operating is progressing a 25 gross (1.9 net) well development on our acreage in the southern Delaware Basin. As of September 30, 2026, 10 gross (0.9 net) wells had been turned to sales, with the remaining wells expected to come online in the fourth quarter of 2026 and first half of 2027.

Previous wording

Oil prices increased during the first half of 2026 compared to the same period in 2025, primarily due to the conflict with Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices were lower during the first half of 2026 relative to the prior-year period. Natural gas prices were elevated early in 2026 due to winter weather and tighter inventories but generally moderated during the remainder of the first six months as production growth increased market supplies. Recent price strength at the end of the second quarter was driven by rising electric power demand and increased U.S. liquefied natural gas ("LNG") export volumes.

Current wording

Oil prices increased during the nine months ended September 30, 2026 compared to the same period in 2025, primarily due to the conflict with Iran and the closure of the Strait of Hormuz. These developments disrupted global crude oil supply chains, including reduced production levels, damage to oil infrastructure, and significant interruptions to shipping activity. Natural gas prices were lower during the nine months ended September 30, 2026 relative to the prior-year period. Natural gas prices were elevated early in 2026 due to winter weather and tighter inventories but moderated later in the first quarter as weather-related demand subsided. As the year progressed, production growth and additional pipeline infrastructure in the Permian Basin increased market supplies. Expectations for milder winter weather further contributed to lower natural gas prices during the third quarter of 2026.

Previous wording

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 Tcf at the end of October 2026, which would be 5% higher than the five-year average.

Current wording

Historically, natural gas supply and demand fluctuate 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") estimated that natural gas inventories concluded the injection season in October 2026 at 3.9 Tcf, which is 2% higher than the five-year average.

Previous wording

Net natural gas exports averaged 17.2 Bcf per day during the second quarter of 2026, a 14% increase from the 2025 average. The EIA forecasts average exports of 17.3 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that LNG exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.

Current wording

LNG exports averaged 17.0 Bcf per day during the third quarter of 2026, a 13% increase from the 2025 average. The EIA forecasts average exports of 18.2 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that LNG exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.

Previous wording

Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three and six months ended June 30, 2025, for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation. Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests.

Current wording

Beginning with the year ended December 31, 2025, we revised our definition of Adjusted EBITDA to exclude seismic data acquisition costs, which are included in Exploration expense on our consolidated statements of operations. Comparative amounts for the three and nine months ended September 30, 2025, for each of Adjusted EBITDA and Distributable Cash Flow have been recast to conform to the current period presentation. Management believes this revised definition enhances comparability between periods and reflects the Partnership’s view of seismic data acquisition costs as investments that support the long-term development and value of its mineral and royalty interests.

Previous wording

Total revenue for the quarter ended June 30, 2026 decreased compared to the quarter ended June 30, 2025. The decrease in total revenue in the second quarter of 2026 is primarily due to lower gains on our commodity derivative instruments and lower natural gas and NGL sales partially offset by increased oil and condensate sales as well as higher lease bonus and other income.

Current wording

Total revenue for the quarter ended September 30, 2026 decreased compared to the quarter ended September 30, 2025. The decrease in total revenue in the third quarter of 2026 is due to losses on our commodity derivative instruments partially offset by increased oil and condensate sales, increased natural gas and NGL sales, and higher lease bonus and other income.

Previous wording

Oil and condensate sales. Oil and condensate sales increased for the quarter ended June 30, 2026 as compared to the corresponding period in 2025 due to increased realized commodity prices. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended June 30, 2026 and 2025.

Current wording

Oil and condensate sales. Oil and condensate sales increased for the quarter ended September 30, 2026 as compared to the corresponding period in 2025 due to increased realized commodity prices, which were partially offset by slightly decreased production volumes. The decrease in oil and condensate production was driven by lower mineral and royalty volumes in the Bakken/Three Forks and the Eagle Ford trends. Our mineral and royalty interest oil and condensate volumes accounted for 95% and 96% of total oil and condensate volumes for the quarters ended September 30, 2026 and 2025, respectively.

Previous wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales decreased for the quarter ended June 30, 2026 as compared to the corresponding prior period. The decrease between the comparative periods is due to lower realized commodity prices and slightly decreased production volumes. The decrease in production was driven by lower royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the quarters ended June 30, 2026 and 2025, respectively.

Current wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended September 30, 2026 as compared to the corresponding prior period. The increase between the comparative periods is due to higher realized commodity prices offset by slightly decreased production volumes. The decrease in production was driven by lower royalty interest volumes, primarily within the Bakken/Three Forks and the Eagle Ford trends. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the quarters ended September 30, 2026 and 2025, respectively.

Previous wording

Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves. During the second quarter of 2026, gains from our commodity derivative instruments decreased compared to the same period in 2025. For the three months ended June 30, 2026, we recognized $8.8 million of realized losses and $35.6 million of unrealized gains from our oil and natural gas commodity contracts, compared to $3.2 million of realized gains and $49.6 million of unrealized gains in the same period in 2025. The unrealized gains on our commodity contracts during the second quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized gains for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.

Current wording

Gain (loss) on commodity derivative instruments. Consistent with our hedging strategy, we generally enter into commodity derivative instruments in advance of the related production periods. As a result, realized settlements and changes in fair value may vary significantly from period to period as commodity prices change relative to our contract prices. 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 2026, we recognized losses from our commodity derivative instruments compared to recognized gains for the same period in 2025. For the three months ended September 30, 2026, we recognized $0.4 million of realized losses and $29.8 million of unrealized losses from our oil and natural gas commodity contracts, compared to $6.9 million of realized gains and $20.4 million of unrealized gains in the same period in 2025. The unrealized losses on our commodity contracts during the third quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized gains for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.

Previous wording

Lease bonus and other income. When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. Lease bonus revenue can vary substantively between periods because it is derived from individual transactions with operators, some of which may be significant. Lease bonus and other income for the second quarter of 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play comprised the majority of lease bonus and other income for the second quarter of 2026, while the majority of lease bonus and other income in the second quarter of 2025 came from leasing activity in the Permian Basin and Bakken/Three Forks plays.

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 substantially 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 2026 was higher than the same period in 2025. Leasing activity in the Permian Basin comprised the majority of lease bonus and other income for the third quarter of 2026, while the majority of lease bonus and other income in the third quarter of 2025 came from leasing activity in the Permian Basin and the Haynesville/Bossier play.

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, 2026, production costs and ad valorem taxes decreased compared to the quarter ended June 30, 2025. The decrease was primarily due to $4.2 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.

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, 2026, production costs and ad valorem taxes decreased compared to the quarter ended September 30, 2025, primarily due to 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, 2026, exploration expenses increased compared to the same period in 2025, primarily due to higher expenditures for seismic costs incurred in connection with ongoing seismic shoots tied to our development programs.

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, 2026, exploration expenses increased compared to the same period in 2025, primarily due to planned expenditures for ongoing proprietary seismic shoots associated with our development programs in the expanded Shelby Trough area.

Previous wording

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended June 30, 2026 as compared to the same period in 2025 due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.

Current wording

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased forthe quarter ended September 30, 2026 as compared to the same period in 2025 due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanded Shelby Trough area.

Previous wording

General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include expenses such as the cost of employee salaries and related benefits, office expenses, and fees for professional services. For the quarter ended June 30, 2026, general and administrative expenses increasedas compared to the same period in 2025, primarily due to higher personnel costs, including $1.2 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

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, 2026, general and administrative expenses increasedas compared to the same period in 2025, primarily due to higher personnel costs, including $2.9 million of cash compensation and $0.8 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Previous wording

Interest expense. Interest expense increasedfor the quarter ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.

Current wording

Interest expense. Interest expense increasedfor the quarter ended September 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outs tanding borrowings under our Credit Facility.

Previous wording

Total revenue for the six months ended June 30, 2026 decreased slightly compared to the corresponding prior period. The decrease in total revenue is primarily due to increased losses on our commodity derivative instruments partially offset by increased oil and condensate sales as well as higher lease bonus and other income.

Current wording

Total revenue for the nine months ended September 30, 2026 decreased compared to the corresponding prior period. The decrease in total revenue is due to losses on our commodity derivative instruments partially offset by increased oil and condensate sales, increased natural gas and NGL sales, and higher lease bonus and other income.

Previous wording

Oil and condensate sales. Oil and condensate sales during the six months ended June 30, 2026 increased compared to the corresponding prior period primarily due to higher production volumes and realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin and Bakken/Three Forks plays. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the six months ended June 30, 2026 and 2025.

Current wording

Oil and condensate sales. Oil and condensate sales during the nine months ended September 30, 2026 increased compared to the corresponding prior period primarily due to higher realized commodity prices and slightly higher production volumes. The increase in oil and condensate production was driven by higher mineral and royalty production in the Permian Basin and Bakken/Three Forks plays. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the nine months ended September 30, 2026 and 2025.

Previous wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the six months ended June 30, 2026 were flat compared to the corresponding prior period. Both commodity prices and production volumes remained relatively consistent between the comparable periods. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the six months ended June 30, 2026 and 2025, respectively.

Current wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales during the nine months ended September 30, 2026 were flat compared to the corresponding prior period. Both commodity prices and production volumes remained relatively consistent between the comparable periods. Mineral and royalty interest production accounted for 97% and 96% of our natural gas volumes for the nine months ended September 30, 2026 and 2025, respectively.

Previous wording

Gain (loss) on commodity derivative instruments. During the six months ended June 30, 2026, we recognized an increased loss from our commodity derivative instruments compared to the corresponding period in 2025. In the six months ended June 30, 2026, we recognized $21.0 million of realized losses and $16.7 million of unrealized losses from our oil and natural gas commodity contracts, compared to $0.5 million of realized losses and $2.7 million of unrealized losses in the same period in 2025. Unrealized losses on our commodity contracts during the six months ended June 30, 2026 were driven by changes in forward oil price curves, compared to the corresponding period in 2025 when unrealized losses were driven by changes in forward natural gas price curves.

Current wording

Gain (loss) on commodity derivative instruments. During the nine months ended September 30, 2026, we recognized losses from our commodity derivative instruments compared to recognized gains for the same period in 2025. In the nine months ended September 30, 2026, we recognized $21.4 million of realized losses and $46.5 million of unrealized losses from our oil and natural gas commodity contracts, compared to $6.5 million of realized gains and $17.6 million of unrealized gains in the same period in 2025. Unrealized losses on our commodity contracts during the nine months ended September 30, 2026 were driven by changes in forward oil price curves, compared to the corresponding period in 2025 when unrealized gains were driven by changes in forward oil and natural gas price curves.

Previous wording

Lease bonus and other income. Lease bonus and other income for the six months ended June 30, 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play and proceeds from the surface use waivers on our mineral acreage supporting solar development in Mississippi made up the majority of lease bonus and other income for the six months ended June 30, 2026, while a substantial portion of the activity in the corresponding period in 2025 came from leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana.

Current wording

Lease bonus and other income. Lease bonus and other income for the nine months ended September 30, 2026 was higher than the same period in 2025. Leasing activity in the Haynesville/Bossier play and the Permian Basin, as well as proceeds from the surface use waivers on our mineral acreage supporting solar development in Mississippi, accounted for the majority of lease bonus and other income for the nine months ended September 30, 2026, while a substantial portion of the activity in the corresponding period in 2025 came from leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development in Louisiana.

Previous wording

Lease operating expense. Lease operating expense decreased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to a reduction in nonrecurring service-related expenses, including workovers.

Current wording

Lease operating expense. Lease operating expense decreased for the nine months ended September 30, 2026 as compared to the same period in 2025, primarily due to a reduction in nonrecurring service-related expenses, including workovers.

Previous wording

Production costs and ad valorem taxes. For the six months ended June 30, 2026, production costs and ad valorem taxes decreased as compared to the six months ended June 30, 2025, primarily due to $6.5 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions. The overall decrease was partially offset by higher ad valorem tax estimates and higher production taxes due to increased production revenues.

Current wording

Production costs and ad valorem taxes. For the nine months ended September 30, 2026, production costs and ad valorem taxes decreased as compared to the nine months ended September 30, 2025, primarily due to $6.8 million in refunds of production costs from operators, which resulted from settlements for prior period deduction-free lease terms.

Previous wording

Exploration expense. For the six months ended June 30, 2026, exploration expense increased as compared to the six months ended June 30, 2025. The increase was primarily driven by purchases of seismic data and costs from proprietary seismic projects associated with existing and future development programs in the expanded Shelby Trough area.

Current wording

Exploration expense. For the nine months ended September 30, 2026, exploration expense increased as compared to the nine months ended September 30, 2025. The increase was primarily driven by purchases of seismic data and planned expenditures for ongoing proprietary seismic shoots associated with our development programs in the expanded Shelby Trough area.

Previous wording

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the six months ended June 30, 2026 as compared to the same period in 2025, primarily due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanding Shelby Trough area.

Current wording

Depreciation, depletion, and amortization. Depreciation, depletion, and amortization increased for the nine months ended September 30, 2026 as compared to the same period in 2025, primarily due to higher depletion rates associated with increased capitalized costs from acquisitions in the expanded Shelby Trough area.

Previous wording

General and administrative. For the six months ended June 30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $2.3 million of cash compensation and $0.9 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Current wording

General and administrative. For the nine months ended September 30, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $5.2 million of cash compensation and $1.9 million of equity-based compensation, driven by increased headcount and projected outperformance relative to performance targets under our short-term cash incentive plan. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

Previous wording

Interest expense. Interest expense increased for the six months ended June 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.

Current wording

Interest expense. Interest expense increased for the nine months ended September 30, 2026 as compared to the corresponding period in 2025. The increase was due to higher average outstanding borrowings under our Credit Facility.

Previous wording

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. The Series B cumulative convertible preferred units are entitled to quarterly distributions based on an annual distribution rate (the "Distribution Rate"), which is subject to adjustment every two years (each, a "Readjustment Date") with the last Readjustment Date on November 28, 2025. 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; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the Distribution Rate shall be increased by 2.0% per annum for such quarter. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date. 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 convertible 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.

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. The Series B cumulative convertible preferred units are entitled to quarterly distributions based on an annual distribution rate (the "Distribution Rate"), which is subject to adjustment every two years (each, a "Readjustment Date") with the last Readjustment Date on November 28, 2025. 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; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the Distribution Rate shall be increased by 2.0% per annum for such quarter. The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for the November 28, 2025 Readjustment Date. 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 convertible 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. The next Readjustment Date is November 28, 2027, with the 90-day redemption window extending through February 25, 2028. 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

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be cancelled. See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. As of June 30, 2026, we had not made any repurchases under the program.

Current wording

On October 30, 2023, the Board authorized a $150.0 million unit repurchase program which authorizes us to make repurchases on a discretionary basis. The program will be funded from our cash on hand or through borrowings under the Credit Facility. Any repurchased units will be canceled. See "Note 11 – Common Units" to the unaudited interim consolidated financial statements included elsewhere in this Quarterly Report on Form 10-Q for additional information. As of September 30, 2026, we had not made any repurchases under the program.

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 increased for the six months ended June 30, 2026 as compared to the same period of 2025. The increase was primarily driven by higher oil sales due to increased realized oil prices and production volumes in the six months ended June 30, 2026. The overall increase was partially offset by higher cash paid for the settlement of commodity derivatives.

Current wording

Operating Activities. Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash flows provided by operating activities increased for the nine months ended September 30, 2026 as compared to the same period of 2025. The increase was primarily driven by higher oil sales due to increased realized oil prices in the nine months ended September 30, 2026. The overall increase was partially offset by higher cash paid for the settlement of commodity derivatives.

Previous wording

Investing Activities. Net cash used in investing activities in the six months ended June 30, 2026 increased as compared to the same period of 2025. The increase was primarily due to higher expenditures for acquisitions of oil and natural gas properties and leasehold costs in the six months ended June 30, 2026 compared to the same period of 2025.

Current wording

Investing Activities. Net cash used in investing activities in the nine months ended September 30, 2026 increased as compared to the same period of 2025. The increase was primarily due to higher expenditures for acquisitions of oil and natural gas properties and leasehold costs, and purchases of other property and equipment in the nine months ended September 30, 2026 compared to the same period of 2025.

Previous wording

Financing Activities. Net cash used in financing activities remained consistent for the six months ended June 30, 2026 as compared to the same period of 2025. The decreased distributions paid to common unitholders for the six months ended June 30, 2026, compared to the same period of 2025 was partially offset by higher repayments of our Credit Facility.

Current wording

Financing Activities. Net cash used in financing activities remained consistent for the nine months ended September 30, 2026 as compared to the same period of 2025. The decrease in distributions paid to common unitholders for the nine months ended September 30, 2026, compared to the same period of 2025, was partially offset by lower net borrowings under our Credit Facility.

Previous wording

Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.3 million during the six months ended June 30, 2026. We also spent $6.3 million to acquire leases in areas around our drilling programs during the six months ended June 30, 2026.

Current wording

Expenditures for drilling, completion, and recompletion activities associated with our non-operated working interests were $0.4 million during the nine months ended September 30, 2026. We also spent $10.6 million to acquire leases in areas around our drilling programs during the nine months ended September 30, 2026.

Previous wording

During the six months ended June 30, 2026, we acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in East Texas from various sellers for an aggregate of $48.7 million, including capitalized direct transaction costs. The consideration paid consisted of $45.9 million in cash that was funded with borrowings under our Credit Facility and funds from operating activities, and $2.8 million in equity, that was funded through the issuance of common units based on the fair value of the common units issued on the acquisition dates. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

Current wording

During the nine months ended September 30, 2026, we acquired mineral and royalty interests that consisted primarily of unproved oil and natural gas properties in the expanded Shelby Trough from various sellers for an aggregate of $63.3 million, including capitalized direct transaction costs. The consideration paid consisted of $60.5 million in cash, funded with borrowings under our Credit Facility and funds from operating activities, and the issuance to the sellers of common units of the Partnership with an aggregate fair value of $2.8 million on the respective acquisition dates. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

Previous wording

We have two JEAs originally entered into with Aethon Energy and now operated by Adamas, covering a portion of our acreage in San Augustine County and Angelina County in East Texas. The agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas.

Current wording

We have two JEAs with Adamas, covering a portion of our acreage in Angelina County and San Augustine County in East Texas. The agreements provide for a combined annual minimum drilling commitment of 16 wells across both contract areas.

Previous wording

Adamas drilled a total of 14 wells during the program year that ended on June 30, 2026 and applied 2 of its 10 banked wells toward its commitment. As of July 31, 2026, 8 of those wells had not yet turned to sales and are expected to begin production during the remainder of 2026. Adamas expects to drill 17 wells in the next program year that began in July 2026.

Current wording

Adamas drilled a total of 14 wells during the previous program year that ended on June 30, 2026 and applied 2 of its 10 banked wells toward its commitment. As of September 30, 2026, 9 of those wells had turned to sales, 4 are expected to begin production during the remainder of 2026, and the remaining well is under further evaluation. As of September 30, 2026, Adamas spud 6 of the total 17 wells expected to be drilled in the current program year ending on June 30, 2027.

Previous wording

In November 2025, we entered into an amendment to the JEA that maintained the original 6-well commitment for Program Year 1, while revising the structure for subsequent years. After Program Year 1, well count commitments convert to completed gross lateral-foot commitments at a ratio of one well per 7,000 lateral feet, allowing Revenant to drill longer laterals while maintaining overall commitment levels.

Current wording

In November 2025, we entered into an amendment to the JEA that maintained the original 6-well commitment for Program Year 1 and converted the drilling commitments for subsequent program years to completed gross lateral-foot commitments at a ratio of one well per 7,000 lateral feet.

Previous wording

1 Lateral-feet drilled in any AOI may be used to satisfy drilling commitments in other AOIs, except for the AOI 2 commitment in Program Year 2.

Current wording

1 Lateral feet drilled in any AOI may be used to satisfy drilling commitments in other AOIs, except for 7,000 gross lateral feet of the AOI 2 commitment in Program Year 4, which must be drilled in AOI 2.