Black Stone Minerals, L.P.

Previous wording

•the level of drilling activity by our operators particularly in areas such as the Haynesville where we have concentrated acreage positions;

Current wording

•the level of drilling activity by our operators particularly in areas such as the Shelby Trough and Haynesville where we have concentrated acreage positions;

Previous wording

•domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products;

Current wording

•domestic and foreign trade policies, including tariffs and other controls on imports or exports of goods, including energy products and energy-related products;

Previous wording

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

Current wording

We are one of the largest owners and managers of oil and natural gas mineral interests in the United States ("U.S."). Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management. We maximize value through marketing our mineral assets for lease and creatively structuring the terms on those leases to encourage and accelerate drilling activity. We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders. Alongside our primary focus on traditional revenue streams from our asset base, we will continue to explore the relevance of our assets in energy transition, including opportunities in renewable energy and carbon sequestration.

Previous wording

As of September 30, 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.

Current wording

As of March 31, 2026, our mineral and royalty interests were located in 41 states in the continental U.S., 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. 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

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.

Current wording

During the first quarter, Adamas Energy (formerly Aethon Energy, "Adamas") was operating three rigs on our Angelina and San Augustine acreage in the Shelby Trough. Adamas’s development program remains on track, with 4 wells spud in the first quarter of 2026 as part of the current program year ending June 30, 2026, an additional 4 wells expected in the second quarter of 2026 to complete that program year, and 10 more wells expected in the second half of 2026 as part of the next program year. Adamas successfully turned to sales 7 gross (0.5 net) wells during the first quarter and expects to turn to sales 12 gross (1.2 net) wells during the remainder of 2026.

Previous wording

Given the dynamic nature of these events, including uncertainty regarding changes in trade policies and their resulting consequences, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

Current wording

Given the dynamic nature of commodity markets, we cannot reasonably estimate how long price levels or market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

Previous wording

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.

Current wording

The majority of the production volumes attributable to our interests is derived from natural gas production. Natural gas prices are significantly influenced by storage levels throughout the year. Accordingly, we monitor the natural gas storage reports regularly in the evaluation of our business and its outlook.

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 2025 at 4.0 Tcf, which is 5% higher than the five-year average.

Current wording

Historically, natural gas supply and demand fluctuates on a seasonal basis. From April to October, when the weather is warmer and natural gas demand is lower, natural gas storage levels generally increase. From November to March, storage levels typically decline as utility companies draw natural gas from storage to meet increased heating demand due to colder weather. In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months. The U.S. Energy Information Administration ("EIA") expects inventories will rise to 4.0 Tcf at the end of October 2026, which would be 6% higher than the five-year average.

Previous 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.

Current wording

Net natural gas exports averaged 17.5 Bcf per day during the first quarter of 2026, a 16% increase from the 2025 average. The EIA forecasts average exports of 16.8 Bcf per day for the remainder of 2026 and 18.6 Bcf per day for 2027. The EIA forecast reflects assumptions that U.S. liquefied natural gas ("LNG") exports will increase as new LNG export projects begin operations in 2026. While geopolitical developments, including the conflict in Iran, have increased global energy market volatility, their near-term impact on U.S. natural gas prices has been limited given constrained LNG export capacity.

Previous wording

The prices we receive for oil, natural gas, and NGLs vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the United States.

Current wording

The prices we receive for oil, natural gas, and natural gas liquids ("NGLs") vary by geographical area. The relative prices of these products are determined by the factors affecting global and regional supply and demand dynamics, such as economic conditions, production levels, availability of transportation, weather cycles, and other factors. In addition, realized prices are influenced by product quality and proximity to consuming and refining markets. Any differences between realized prices and New York Mercantile Exchange ("NYMEX") prices are referred to as differentials. All our production is derived from properties located in the U.S.

Previous wording

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end user markets.

Current wording

Natural gas, which currently has a limited global transportation system, is subject to price variances based on local supply and demand conditions and the cost to transport natural gas to end-user markets. Although the growth in LNG export capacity and global shipping has increased connectivity among certain markets, transportation remains infrastructure-dependent and subject to capacity constraints, and prices may continue to vary by region.

Previous wording

Our open derivative contracts consist of fixed-price swap contracts. Under fixed-price swap contracts, a counterparty is required to make a payment to us if the settlement price is less than the swap strike price. Conversely, we are required to make a payment to the counterparty if the settlement price is greater than the swap strike price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments.

Current wording

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations. From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. Under a fixed-price swap contract, a counterparty is required to make a payment to us if the settlement price is less than the contract strike price, and we are required to make a payment to the counterparty if the settlement price is greater than the contract strike price. Under a costless collar contract, we receive a payment from the counterparty if the settlement price is below the floor price, and we make a payment to the counterparty if the settlement price is above the ceiling price. If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. The impact of these derivative instruments could affect the amount of revenue we ultimately realize.

Previous wording

We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of September 30, 2025 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

Current wording

Our open derivative contracts consist of fixed-price swap contracts. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations. If commodity prices decline in the future, our hedging contracts will partially mitigate the effect of lower prices on our future revenue. Our open oil and natural gas derivative contracts as of March 31, 2026 are detailed in Note 4 - Commodity Derivative Financial Instruments to our unaudited consolidated financial statements included elsewhere in this Quarterly Report.

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, 2025, we have hedged a portion of our expected future volumes for the remainder of 2025, 2026, and 2027.

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, 2026, we had hedged a portion of our expected future volumes for the remainder of 2026 and 2027.

Previous wording

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, unrealized gains and losses on commodity derivative instruments, non-cash equity-based compensation, and gains and losses on sales of assets, if any. We define Distributable cash flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Current wording

We define Adjusted EBITDA as net income (loss) before interest expense, income taxes, and depreciation, depletion, and amortization adjusted for impairment of oil and natural gas properties, if any, accretion of asset retirement obligations, seismic data acquisition costs, non-cash equity-based compensation, unrealized gains and losses on commodity derivative instruments, and gains and losses on sales of assets, if any. We define Distributable Cash Flow as Adjusted EBITDA plus or minus amounts for certain non-cash operating activities, cash interest expense, distributions to preferred unitholders, and restructuring charges, if any.

Previous wording

Adjusted EBITDA and Distributable cash flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance presented in accordance with generally accepted accounting principles ("GAAP") in the United States as measures of our financial performance.

Current wording

Adjusted EBITDA and Distributable Cash Flow should not be considered an alternative to, or more meaningful than, net income (loss), income (loss) from operations, cash flows from operating activities, or any other measure of financial performance or liquidity presented in accordance with generally accepted accounting principles ("GAAP") in the U.S. as measures of our financial performance.

Previous wording

The following table presents a reconciliation of net income (loss), the most directly comparable GAAP financial measure, to Adjusted EBITDA and Distributable cash flow for the periods indicated:

Current wording

The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated:

Previous 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.

Current wording

Total revenue for the quarter ended March 31, 2026 increased compared to the quarter ended March 31, 2025. The increase in total revenue in the first quarter of 2026 is primarily due to higher oil and condensate sales and higher natural gas and NGL sales, which were partially offset by increased losses on our commodity derivative instruments and lower lease bonus and other income compared to the corresponding prior period.

Previous 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.

Current wording

Oil and condensate sales. Oil and condensate sales increased for the quarter ended March 31, 2026 as compared to the corresponding period in 2025 primarily due to increased production volumes, which were partially offset by slightly decreased realized commodity prices. The increase in oil and condensate production was driven by higher mineral and royalty volumes in the Permian Basin and the Eagle Ford trends. Our mineral and royalty interest oil and condensate volumes accounted for 96% of total oil and condensate volumes for each of the quarters ended March 31, 2026 and 2025.

Previous wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended September 30, 2025 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods partially offset by a decrease in production volumes. The decrease in production was driven by reduced royalty interest volumes, primarily within the Haynesville/Bossier play. Mineral and royalty interest production accounted for 96% and 94% of our natural gas volumes for the quarters ended September 30, 2025 and 2024, respectively.

Current wording

Natural gas and natural gas liquids sales. Natural gas and NGL sales increased for the quarter ended March 31, 2026 as compared to the corresponding prior period. The increase was due to higher realized commodity prices between the comparative periods and increased production volumes. The increase in production was driven by higher royalty interest volumes, primarily within the Haynesville/Bossier trend. Mineral and royalty interest production accounted for 97% of our natural gas volumes for each of the quarters ended March 31, 2026 and 2025.

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 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.

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 2026, losses from our commodity derivative instruments increased compared to the same period in 2025. For the three months ended March 31, 2026, we recognized $12.2 million of realized losses and $52.3 million of unrealized losses from our oil and natural gas commodity contracts, compared to $3.6 million of realized losses and $52.4 million of unrealized losses in the same period in 2025. The unrealized losses on our commodity contracts during the first quarter of 2026 were primarily driven by changes in the forward commodity price curves for oil. The unrealized losses for the same period in 2025 were primarily driven by changes in the forward commodity price curves for natural gas.

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 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.

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 2026 was lower than the same period in 2025. Leasing activity in the Permian Basin and proceeds from surface use waivers on our mineral acreage supporting solar development comprised the majority of lease bonus and other income for both the first quarter of 2026 and the first quarter of 2025. The surface use waivers covered mineral acreage in Mississippi for the first quarter of 2026 and Louisiana for the first quarter of 2025.

Previous wording

Lease operating expense. Lease operating expense includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense increased for the quarter ended September 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 includes recurring expenses associated with our non-operated working interests necessary to produce hydrocarbons from our oil and natural gas wells, as well as certain nonrecurring expenses, such as well repairs. Lease operating expense decreased for the quarter ended March 31, 2026 as compared to the same period in 2025, primarily due to lower nonrecurring service-related expenses, including workovers.

Previous wording

Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities. Depending on the regulations of the states where the production originates, these taxes may be based on a percentage of the realized value or a fixed amount per production unit. This category also includes the costs to process and transport our production to applicable sales points. Ad valorem taxes are jurisdictional taxes levied on the value of oil and natural gas minerals and reserves. Rates, methods of calculating property values, and timing of payments vary between taxing authorities. For the quarter ended 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.

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, 2026, production costs and ad valorem taxes decreased compared to the quarter ended March 31, 2025. The decrease was primarily due to $2.3 million in refunds of production costs from operators associated with deduction-free lease terms, reflecting settlements of prior period deductions, as well as lower ad valorem tax estimates. The overall decrease was partially offset by higher production taxes due to increased production revenues and volumes.

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 decreased for the quarter ended September 30, 2025 as compared to the same period in 2024 due to lower production volumes.

Current wording

Depreciation, depletion, and amortization. Depletion is the amount of cost basis of oil and natural gas properties attributable to the volume of hydrocarbons extracted during a period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs. Depreciation, depletion, and amortization increased for the quarter ended March 31, 2026 as compared to the same period in 2025 due to higher production volumes.

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, 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.

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, 2026, general and administrative expenses increased as compared to the same period in 2025, primarily due to higher personnel costs, including $1.1 million of cash compensation and $0.5 million of equity-based compensation, driven by increased headcount. The increase in equity-based compensation was also driven by higher costs for performance-based awards due to mark-to-market adjustments reflecting changes in our common unit price during 2026 compared to 2025.

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. 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.

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, 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

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with our executed farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

Current wording

We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt. Over the long-term, we intend to finance our working interest capital needs with farmout agreements and internally generated cash flows, although at times we may fund a portion of these expenditures through other financing sources such as borrowings under our Credit Facility.

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.

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 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 March 31, 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 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.

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, 2026 as compared to the same period of 2025. The decrease was primarily due to increased interest expense in the three months ended March 31, 2026, that resulted from higher average outstanding borrowings under our Credit Facility.

Previous 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.

Current wording

Investing Activities. Net cash used in investing activities in the three months ended March 31, 2026 decreased as compared to the same period of 2025. The decrease was primarily due to reduced amounts paid for oil and natural gas properties leasehold costs in the three months ended March 31, 2026 compared to the same period of 2025. The overall decrease was partially offset by higher acquisitions of oil and natural gas properties.

Previous 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.

Current wording

Financing Activities. Net cash used in financing activities decreased for the three months ended March 31, 2026 as compared to the same period of 2025. The decrease was primarily driven by lower distributions paid to common unitholders for the three months ended March 31, 2026, compared to the same period of 2025. The overall decrease was partially offset by lower net borrowings under our Credit Facility.

Previous 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.

Current wording

During the three months ended March 31, 2026, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties in East Texas from various sellers for cash consideration of $11.5 million, including capitalized direct transaction costs. The consideration paid was funded from borrowings under our Credit Facility and funds from operating activities. Our commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions.

Previous wording

We are party to a series of JEAs with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage in exchange for meeting minimum annual drilling commitments. Each JEA also includes a banked well provision, which allows operators that exceed their annual drilling commitments to carry forward excess wells to satisfy future obligations, subject to defined caps. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs.

Current wording

We are party to a series of Joint Exploration Agreements ("JEAs"; each, a "JEA") with unaffiliated operators covering portions of our undeveloped leasehold and mineral acreage in the Shelby Trough area of East Texas. These agreements grant the operator exclusive rights to develop designated acreage and reduced royalty rates in exchange for meeting minimum annual drilling commitments, as defined by either a minimum number of wells or minimum aggregate lateral feet drilled. Each JEA also includes a banking provision that allows operators that exceed their annual drilling commitments to carry forward excess drilling activity, measured by wells drilled or aggregate lateral feet, to satisfy future obligations, subject to defined caps. The agreements also allow operators to temporarily suspend drilling obligations if natural gas prices fall below certain thresholds. The duration of any such suspension period is subject to limitations specified in the agreements. Wells drilled are typically required to turn to sales within 260 days of rig release. The agreements are structured to generate value from our undeveloped acreage while limiting our exposure to capital and operational costs.

Previous 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.

Current 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.

Previous 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.

Current wording

Adamas expects to drill a total of 14 wells in the current program year, ending June 30, 2026, and apply 2 of its banked wells toward its commitment. As of March 31, 2026, Adamas had spud 10 wells in the current program year and had a total of 10 banked wells.

Previous wording

In May 2025, we entered into a JEA with Revenant covering an expanded portion of our Shelby Trough acreage, primarily located in Angelina, Nacogdoches, and San Augustine counties in Texas. The agreement grants Revenant exclusive development rights across three designated areas of interest ("AOIs") and requires annual well commitments, including test wells in certain areas, to maintain development rights across the full contract area. The agreement allows for non-operated working interest participation, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our undivided 35% working interest.

Current wording

In May 2025, we entered into a JEA with Revenant covering an expanded portion of our Shelby Trough acreage, primarily located in Angelina, Nacogdoches, and San Augustine counties in Texas. The agreement grants Revenant exclusive development rights across three designated areas of interest ("AOIs") and requires minimum annual drilling commitments that escalate over a five-year period, including test wells in certain areas, to maintain development rights across the full contract area. The agreement allows for non-operated working interest participation, and in June 2025 we entered into a farmout agreement with an external capital provider covering all of our undivided 35% working interest.

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. 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.

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, 2030. 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. We reaffirmed the borrowing base in April 2025, October 2025 and April 2026 at $580.0 million. After each redetermination, we elected to maintain cash commitments under the Credit Facility at $375.0 million. The next semi-annual redetermination is scheduled for October 2026.

Previous wording

As of September 30, 2025, there have been no material changes to our contractual obligations previously disclosed in our 2024 Annual Report on Form 10-K.

Current wording

As of March 31, 2026, there have been no material changes to our material cash requirements previously disclosed in our 2025 Annual Report on Form 10-K.