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What changed in Black Stone Minerals, L.P.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of Black Stone Minerals, L.P.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+220 added−206 removedSource: 10-K (2026-02-24) vs 10-K (2025-02-25)

Top changes in Black Stone Minerals, L.P.'s 2025 10-K

220 paragraphs added · 206 removed · 174 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

76 edited+7 added−9 removed225 unchanged
Biggest changeAny acquisition involves potential risks, including, among other things: • the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs; • a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; • the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate; • mistaken assumptions about the overall cost of equity or debt; • our ability to obtain satisfactory title to the assets we acquire; • an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; and • the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges. 29 Environmental, Legal and Regulatory Risks Conservation measures, technological advances , and general concern about the environmental impact of the production and use of fossil fuels could materially reduce demand for oil and natural gas and adversely affect our results of operations and the trading market for our common units.
Biggest changeAny acquisition involves potential risks, including, among other things: • the validity of our assumptions about estimated proved reserves, future production, prices, revenues, capital expenditures, operating expenses, and costs; • a decrease in our liquidity by using a significant portion of our cash generated from operations or borrowing capacity to finance acquisitions; • a significant increase in our interest expense or financial leverage if we incur debt to finance acquisitions; • the assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which any indemnity we receive is inadequate; • mistaken assumptions about the overall cost of equity or debt; • our ability to obtain satisfactory title to the assets we acquire; • an inability to hire, train, or retain qualified personnel to manage and operate our growing business and assets; • investments in seismic and other subsurface data may not identify commercially viable prospects or support successful development or acquisitions; and • the occurrence of other significant changes, such as impairment of oil and natural gas properties, goodwill or other intangible assets, asset devaluation, or restructuring charges.
The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors largely outside of our control, including: • the capital costs required for drilling activities by our operators, which could be significantly more than anticipated; • the ability of our operators to access capital; • prevailing commodity prices; • the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel; • the operators’ expertise, operating efficiency, and financial resources; • approval of other participants in drilling wells; • the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; • the selection of technology; • the selection of counterparties for the marketing and sale of production; and • the rate of production of the reserves.
The success and timing of drilling and development activities on our properties, and whether the operators elect to drill any additional wells on our acreage, depends on a number of factors largely outside of our control, including: • the capital costs required for drilling activities by our operators, which could be significantly more than anticipated; • the ability of our operators to access capital; • prevailing commodity prices; 27 • the availability of suitable drilling equipment, production and transportation infrastructure, and qualified operating personnel; • the operators’ expertise, operating efficiency, and financial resources; • approval of other participants in drilling wells; • the operators’ expected return on investment in wells drilled on our acreage as compared to opportunities in other areas; • the selection of technology; • the selection of counterparties for the marketing and sale of production; and • the rate of production of the reserves.
The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding such matters as: • amount and timing of asset purchases and sales; • cash expenditures; • borrowings and repayment of current and future indebtedness; • redemption of all or a portion of the Series B cumulative convertible preferred units; • issuance of additional units; and • the creation, reduction, or increase of reserves in any quarter.
The amount of cash generated from operations available for distribution to unitholders is affected by decisions of our general partner regarding such matters as: • amount and timing of asset purchases and sales; • cash expenditures; 35 • borrowings and repayment of current and future indebtedness; • redemption of all or a portion of the Series B cumulative convertible preferred units; • issuance of additional units; and • the creation, reduction, or increase of reserves in any quarter.
“Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.” Our operators’ development activities on our leases, funding our non-operated working interests, and acquisitions will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
“Market for Registrant’s Common Equity, Related Unitholder Matters, and Issuer Purchases of Equity Securities — Cash Distribution Policy.” 29 Our operators’ development activities on our leases, funding our non-operated working interests, and acquisitions will require substantial capital, and we and our operators may be unable to obtain needed capital or financing on satisfactory terms or at all.
These and other potential regulations could increase the operating costs of our operators and delay production, which could adversely affect the amount of cash available for distribution to our unitholders. 30 Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse. We own mineral servitudes covering several hundred thousand acres in Louisiana.
These and other potential regulations could increase the operating costs of our operators and delay production, which could adversely affect the amount of cash available for distribution to our unitholders. Louisiana mineral servitudes are subject to reversion to the surface owner after ten years’ nonuse. We own mineral servitudes covering several hundred thousand acres in Louisiana.
We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. 31 We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance providers within the time frame required under our insurance policy.
We may also be liable for environmental damage caused by previous owners of properties purchased by us, which liabilities may not be covered by insurance. We may not have coverage if we are unaware of a sudden and accidental pollution event and unable to report the “occurrence” to our insurance providers within the time frame required under our insurance policy.
Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently 26 expected.
Our operators are often not obligated to undertake any development activities other than those required to maintain their leases on our acreage. In the absence of a specific contractual obligation, any development and production activities will be subject to their reasonable discretion. Our operators could determine to drill and complete fewer wells on our acreage than is currently expected.
If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. 28 If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.
If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow. If we issue additional units in connection with any acquisitions or growth capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level.
Consideration of ESG-related factors in our decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties and increase litigation risks from private parties and governmental authorities. 32 Key Persons We rely on a few key individuals whose absence or loss could adversely affect our business.
Consideration of ESG-related factors in our decision-making could be subject to increasing scrutiny and objection from such anti-ESG parties and increase litigation risks from private parties and governmental authorities. Key Persons We rely on a few key individuals whose absence or loss could adversely affect our business.
As a result, we are not insured against any losses resulting from the death of these key individuals. Title Defects Title to the properties in which we have an interest may be impaired by title defects. No assurance can be given that we will not suffer a monetary loss from title defects or title failure.
As a result, we are not insured against any losses resulting from the death of these key individuals. 33 Title Defects Title to the properties in which we have an interest may be impaired by title defects. No assurance can be given that we will not suffer a monetary loss from title defects or title failure.
For a transfer of an interest in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and future prospective non-U.S. common unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
For a transfer of an interest in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. common unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the trend of more expansive and stricter environmental legislation and regulations will continue.
Our operators may be required to make significant expenditures to comply with the governmental laws and regulations described above and may be subject to potential fines and penalties if they are found to have violated these laws and regulations. We believe the general trend of more expansive and stricter environmental legislation and regulations will continue.
However, subject to certain exceptions, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the Series B cumulative convertible preferred units with respect to 34 rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.
However, subject to certain exceptions, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the Series B cumulative convertible preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.
In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder 35 approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.
In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances. Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.
Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
Such legislative changes have included, but not been limited to, (i) the repeal of the percentage depletion allowance for oil and natural gas 37 properties; (ii) the elimination of current deductions for intangible drilling and development costs; and (iii) an extension of the amortization period for certain geological and geophysical expenditures.
The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S. natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, and rising levels of U.S. natural gas exports.
The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S. natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, and levels of U.S. natural gas exports.
While such ratings do not impact all investors’ investment or voting decisions, unfavorable ESG ratings may lead to negative investor sentiment toward us and to the diversion of investment which could have a negative impact on our unit price and/or our access to and costs of capital.
While such ratings or recommendations do not impact all investors’ investment or voting decisions, unfavorable ESG ratings or recommendations may lead to negative investor sentiment toward us and to the diversion of investment which could have a negative impact on our unit price and/or our access to and costs of capital.
As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes 38 and subject to such 10% withholding tax.
As we do not compute our cumulative net income for such purposes due to the complexity of the calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax.
There can be no assurance that there will not be further changes to U.S. federal income tax laws or 36 the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department's interpretation of the qualifying income rules in a manner that could impact our ability to qualify as a partnership in the future.
If the operation results in production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.
If the operation results in 31 production, prescription is interrupted as long as the production continues or operations are conducted in good faith to secure or restore production. If any of our mineral servitudes are prescribed by operation of Louisiana law, our operating results may be adversely affected.
We own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on 39 corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions.
We own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities. You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions.
A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders. Increased attention to environmental, social and governance (ESG) matters may impact our business.
A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders. 32 Increased attention to environmental, social and governance (ESG) matters may impact our business.
To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, executed farmout agreements, and the issuance of equity securities.
To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, farmout agreements, and the issuance of equity securities.
The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations, and cash distributions to unitholders.
The impact of the changing demand for oil and natural gas services and products may have a material adverse effect on our 30 business, financial condition, results of operations, and cash distributions to unitholders.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate recoveries, and operating and development costs.
Oil and natural gas reserve engineering is not an exact science and requires subjective estimates of underground accumulations of oil and natural gas and assumptions concerning future oil and natural gas prices, production levels, ultimate 26 recoveries, and operating and development costs.
Further, any actual or perceived failure to comply with any new or existing laws, regulations and other obligations could result in fines, penalties or other liability. 40 ITEM 1B. UNRESOLVED STAFF COMMENTS None.
Further, any actual or perceived failure to comply with any new or existing laws, regulations and other obligations could result in fines, penalties or other liability. ITEM 1B. UNRESOLVED STAFF COMMENTS None.
We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition, results of operations, and cash distributions to our common unitholders. 24 We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.
We may also not be able to find, acquire, or develop additional reserves to replace the current and future production of our properties at economically acceptable terms, which would adversely affect our business, financial condition, results of operations, and cash distributions to our common unitholders. 25 We either have little or no control over the timing of future drilling with respect to our mineral and royalty interests and non-operated working interests.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above. Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.
Unitholders are bound by the provisions of our partnership agreement, including the provisions described above. 34 Our partnership agreement restricts the voting rights of unitholders owning 15% or more of our units, subject to certain exceptions.
The estimates of reserves as of December 31, 2024, 2023, and 2022 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2024, 2023, and 2022, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods.
The estimates of reserves as of December 31, 2025, 2024, and 2023 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2025, 2024, and 2023, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods.
Under certain conditions, we may elect to convert all or any portion of the Series B cumulative convertible preferred units into common units. As of December 31, 2024 and through the date of this filing, we had not met all such conditions and therefore were not eligible to exercise our conversion right for the Series B cumulative convertible preferred units.
Under certain conditions, we may elect to convert all or any portion of the Series B cumulative convertible preferred units into common units. As of December 31, 2025 and through the date of this filing, we had not met all such conditions and therefore were not eligible to exercise our conversion right for the Series B cumulative convertible preferred units.
Finally, certain employment practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve.
Finally, certain employment or business practices and social initiatives are the subject of scrutiny by both those calling for the continued advancement of such policies, as well as those who believe they should be curbed, including government actors, and the complex regulatory and legal frameworks applicable to such initiatives continue to evolve.
Our estimates of proved reserves and related valuations as of December 31, 2024, 2023, and 2022 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailed review of our properties for the period covered by its reserve report using information provided by us.
Our estimates of proved reserves and related valuations as of December 31, 2025, 2024, and 2023 were prepared by NSAI, a third-party petroleum engineering firm, which conducted a detailed review of our properties for the period covered by its reserve report using information provided by us.
For the year ended December 31, 2024, we received revenue from over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues.
For the year ended December 31, 2025, we received revenue from over 1,000 operators. The failure of our operators to adequately or efficiently perform operations or an operator’s failure to act in ways that are in our best interests could reduce production and revenues.
Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from our operations and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.
Therefore, treatment of us as a corporation or the assessment of a material amount of entity-level taxation would result in a material reduction in the anticipated cash generated from our operations and after-tax returns to our common unitholders, likely causing a substantial reduction in the value of our common units.
Increased attention to, and sometimes conflicting social expectations on, companies to address climate change and other environmental and social impacts, investor and societal expectations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our unit price and access to capital markets.
Increased attention to, and sometimes conflicting social expectations on, companies to address climate change, investor and societal expectations regarding ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our unit price and access to capital markets.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including: • the domestic and foreign supply of and demand for oil and natural gas; • market expectations about future prices of oil and natural gas; • the level of global oil and natural gas exploration and production; • the cost of exploring for, developing, producing, and delivering oil and natural gas; • the price and quantity of foreign imports and exports of oil and natural gas; 22 • political and economic conditions in oil producing regions, including the Middle East, Africa, South America, and Russia; • the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; • trading in oil and natural gas derivative contracts; • the level of consumer product demand; • weather conditions and natural disasters; • technological advances affecting energy consumption; • domestic and foreign governmental regulations and taxes, including tariffs and other controls on imports or exports of goods, including energy products; • the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; • global geopolitical conflict, including the ongoing war in Ukraine, conflict in the Middle East and the relationships between the United States and other countries, such as China and Russia; • the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of alternative fuels; and • overall domestic and global economic conditions.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including: • the domestic and foreign supply of and demand for oil and natural gas; • market expectations about future prices of oil and natural gas; • the level of global oil and natural gas exploration and production; • the cost of exploring for, developing, producing, and delivering oil and natural gas; • the price and quantity of foreign imports and exports of oil and natural gas; 23 • political and economic conditions in oil producing regions, including the Middle East, Africa, South America, including Venezuela, and Russia; • the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls; • trading in oil and natural gas derivative contracts; • the level of consumer product demand; • weather conditions and natural disasters; • technological advances affecting energy consumption; • domestic and foreign governmental regulations and taxes, including tariffs and other controls on imports or exports of goods, including energy products; • the continued threat of terrorism and the impact of military and other action, including U.S. military operations in the Middle East; • global geopolitical conflicts and developments, including the ongoing conflict in Ukraine, hostilities in the Middle East, the evolving situation in Venezuela and the relationships between the United States and other countries, such as China and Russia; • the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of alternative fuels; and • overall domestic and global economic conditions.
Approximately 37% of our 2024 oil and natural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay quarterly distributions on our common units, perhaps materially.
Approximately 48% of our 2025 oil and natural gas revenues were derived from natural gas and natural gas liquids sales. Any future decreases in prices of natural gas may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay quarterly distributions on our common units, perhaps materially.
Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us.
Increased attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us or our operators.
Any actions taken by the United States’ federal government that restrict or otherwise impact the economics of trade—including tariffs, trade barriers, or other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly.
Trade policies, such as tariffs, could adversely affect our operations, costs, and business Any actions taken by the United States’ federal government that restrict or otherwise impact the economics of trade—including tariffs, trade barriers, or other similar measures—could have the potential to disrupt existing supply chains and trigger retaliatory efforts by other countries, including the imposition of tariffs, raising taxation, setting foreign exchange or capital controls, or establishing embargos, sanctions, or other import/export restrictions, thereby negatively impacting our business, both directly and indirectly.
Geographic and operator concentration heightens the effect of operational risks, including: • operators’ diversion of drilling capital to other areas, where our royalty interest is less meaningful or nonexistent; • adverse changes to the operators’ financial positions; • unanticipated geographic or environmental constraints in the Shelby Trough; or • delay or cancellation of construction or operation of LNG export facilities in the Gulf of Mexico.
Geographic and operator concentration heightens the effect of operational risks, including: • operators’ diversion of drilling capital to other areas, where our royalty interest is less meaningful or nonexistent; • adverse changes to the operators’ financial positions; • unanticipated geographic or environmental constraints in the Shelby Trough; • delay or cancellation of construction or operation of LNG export facilities in the Gulf of Mexico; or • delay, cancellation, or reduced demand from planned data centers.
During the ten years prior to December 31, 2024, natural gas prices at Henry Hub have ranged from a high of $23.86 per MMBtu in 2021 to a low of $1.21 per MMBtu in 2024. On December 31, 2024, the last trading day of 2024, the Henry Hub spot market price of natural gas was $3.40 per MMBtu.
During the ten years prior to December 31, 2025, natural gas prices at Henry Hub have ranged from a high of $23.86 per MMBtu in 2021 to a low of $1.21 per MMBtu in 2024 . On December 31, 2025, the last trading day of 2025, the Henry Hub spot market price of natural gas was $4.00 per MMBtu.
Relatedly, California has enacted laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. Other states are expected to follow. Non-compliance with these laws may result in the imposition of substantial fines or penalties.
For example, California has enacted laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. Other states are expected to follow. Non-compliance with these laws, to the extent applicable, may result in the imposition of substantial fines or penalties.
During the ten years prior to December 31, 2024, WTI market prices at Cushing, Oklahoma have ranged from a high of $123.64 per Bbl in 2022 to a low of $8.91 per Bbl in 2020. On December 31, 2024, the last trading day of 2024, the WTI spot market price of oil was $72.44.
During the ten years prior to December 31, 2025, WTI market prices at Cushing, Oklahoma have ranged from a high of $123.64 per Bbl in 2022 to a low of $8.91 per Bbl in 2020. On December 31, 2025, the last trading day of 2025, the WTI spot market price of oil was $57.26.
Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations. In 2024, we generated 10% of our royalty revenues and 18% of our working interest revenues from three operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position.
Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations. In 2025, we generated 13% of our royalty revenues and 14% of our working interest revenues from three operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position.
Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities. 23 Approximately 63% of our 2024 oil and natural gas revenues were derived from oil and condensate sales.
Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities. 24 Approximately 52% of our 2025 oil and natural gas revenues were derived from oil and condensate sales.
Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, decreases in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2024, we had $25.0 million outstanding borrowings a nd the aggregate maximum credit amounts of the lenders wer e $1.0 billion.
Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, decreases in reserves, lending requirements, or regulations or certain other circumstances. As of December 31, 2025, we had $154.0 million outstanding borrowings and the aggregate maximum credit amounts of the lenders were $1.0 billion.
Relatedly, certain organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment and voting decisions.
In addition, certain organizations that provide information, ratings or proxy advisory services to investors on corporate governance and related matters have developed processes for evaluating companies on their approach to ESG matters. Such ratings or recommendations are used by some investors to inform their investment and voting decisions.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such common unitholders' behalf. 37 You, as a common unitholder, are required to pay taxes on your share of our income, even if you do not receive any cash distributions from us.
If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such common unitholders' behalf.
The changes in the price of oil have been caused by many factors, including periods of increasing U.S. oil production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, actions taken by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+"), and fluctuations in demand as a result of the COVID-19 pandemic.
The changes in the price of oil have been caused by many factors, including periods of increasing U.S. oil production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, actions taken by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+"), and geopolitical conflicts and developments.
In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.
In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business. Our estimated reserves are based on many assumptions that may turn out to be inaccurate.
For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual common unitholder is entitled to a deduction equal to 20% of his or her allocable share of our "qualified publicly traded partnership income." For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities.
An individual common unitholder is entitled to a deduction equal to 20% of his or her allocable share of our "qualified publicly traded partnership income." For purposes of the deduction, the term qualified publicly traded partnership income includes the net amount of such unitholder’s allocable share of our income that is effectively connected to our U.S. trade or business activities.
Year Ended December 31, 2024 During the Five Years Prior to December 31, 2024 As of December 31, High Low High 2 Low 3 2024 2023 2022 WTI spot crude oil ($/Bbl) 1 $ 87.69 $ 66.73 $ 123.64 $ 8.91 $ 72.44 $ 71.89 $ 80.16 Henry Hub spot natural gas ($/MMBtu) 1 $ 3.40 $ 1.21 $ 23.86 $ 1.21 $ 3.40 $ 2.58 $ 3.52 1 Source: EIA 2 High prices for WTI and Henry Hub were in 2022 and 2021, respectively. 3 Low prices for WTI and Henry Hub were in 2020 and 2024, respectively.
Year Ended December 31, 2025 During the Five Years Prior to December 31, 2025 As of December 31, High Low High 2 Low 3 2025 2024 2023 WTI spot crude oil ($/Bbl) 1 $ 73.79 $ 57.26 $ 123.64 $ 47.47 $ 57.26 $ 72.44 $ 71.89 Henry Hub spot natural gas ($/MMBtu) 1 $ 9.86 $ 2.65 $ 23.86 $ 1.21 $ 4.00 $ 3.40 $ 2.58 1 Source: EIA 2 High prices for WTI and Henry Hub were in 2022 and 2021, respectively. 3 Low prices for WTI and Henry Hub were in 2021 and 2024, respectively.
Because we cannot match transferors and transferees of our common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to you.
The IRS may challenge this treatment, which could adversely affect the value of the common units. 39 Because we cannot match transferors and transferees of our common units, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations.
If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units held by such investor may be redeemed by us at the then-current market price. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner.
If an investor is not an Eligible Holder, in certain circumstances as set forth in our partnership agreement, units held by such investor may be redeemed by us at the then-current market price.
As of December 31, 2024, we had 210,694,933 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
As of December 31, 2025, we had 211,873,257 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
Additionally, institutional lenders may decide not to provide funding for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital.
Additionally, certain financial institutions may decide not to provide funding or insurance for fossil fuel energy companies based on climate change related concerns, which could affect our access to capital or the ability to complete projects.
Our partnership agreement generally provides that any distributions are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7.0% of the face amount of the preferred units per annum through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter, and (ii) second, to the holders of common units.
Our partnership agreement generally provides that any distributions are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units in an amount equal to 7.0% of the face amount of the preferred units per annum, through November 27, 2023, then adjusting on November 28, 2023 and readjusting every two years thereafter, to a rate equal to the greater of (a) the rate in effect immediately prior to the relevant readjustment and (b) the 10-year Treasury Rate as of such readjustment date plus 5.5% per annum (which rate adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025), and (ii) second, to the holders of common units.
Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable. 33 Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.
Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.
We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.
We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased.
A substantial portion of the amount realized from the sale of your common units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture.
In addition, because the amount realized includes a common unitholder’s share of our nonrecourse liabilities, if you sell your common units, you may incur a tax liability in excess of the amount of cash you receive from the sale. 38 A substantial portion of the amount realized from the sale of your common units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture.
Tax-Related Risks Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation.
The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. 36 Tax-Related Risks Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, and not being subject to a material amount of entity-level taxation.
In addition, the outgoing operator could be subject to bankruptcy proceedings, in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired. 27 Access to Capital and Financing Our Credit Facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
In addition, the outgoing operator could be subject to bankruptcy proceedings, in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired.
Our counsel has advised us that under current law our royalty income should qualify for the deduction, but no assurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction.
Our counsel has advised us that under current law our royalty income should qualify for the deduction, but no assurances can be given that the IRS will not challenge our treatment of royalty income as qualifying for the deduction. 40 General Risk Factors The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment.
Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation. Imposition of any of those taxes may substantially reduce the cash distributions to our common unitholders.
In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, and other forms of taxation.
This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations.
In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators. This scenario may result in our having to make substantial downward adjustments to our estimated proved reserves, which could negatively impact our borrowing base and our ability to fund our operations.
Excludes the period in April 2020 when WTI briefly traded in negative territory. Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
Any prolonged substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders. We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations.
Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed.
If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed.
To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished. In addition, lower oil and natural gas prices may also reduce the amount of oil and natural gas that can be produced economically by our operators.
However, we cannot always hedge the entire exposure of our operations from commodity price volatility. To the extent we do not hedge against commodity price volatility, or our hedges are not effective, our results of operations and financial position may be diminished.
The lenders under our Credit Facility reaffirmed our borrowing bas e in November 2024 a t $580.0 million and we elected to maintain cash commitments at $375.0 million. The next semi -annual redetermination is scheduled for April 2025. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings.
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. The next semi -annual redetermination is scheduled for April 2026.
If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.
As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units. Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate. Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, or deductions would flow through to our common unitholders.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay U.S. federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 21%, and would likely pay state income tax at varying rates.
See "Note 4 - Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information. If any of these risks are realized, production may decrease, reducing cash generated from operations and cash available for distribution.
If any of these risks are realized, production may decrease, reducing cash generated from operations and cash available for distribution.
General Risk Factors The price of our common units may fluctuate significantly, and unitholders could lose all or part of their investment. The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere in these risk factors.
The market price of our common units may be influenced by many factors, some of which are beyond our control, including those described elsewhere in these risk factors. If we fail to develop or maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud.
Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders.
Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement. Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders.
Because an entity-level tax would be imposed upon us as a corporation, cash distributions to our common unitholders would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states.
Distributions to our common unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions, or credits would flow through to our common unitholders. Because an entity-level tax would be imposed upon us as a corporation, cash distributions to our common unitholders would be substantially reduced.
At this time, it is unclear what actions the Trump Administration may take, if any at all, with respect to the DOE study. Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
Removed
We may use various derivative instruments in connection with anticipated oil and natural gas sales to minimize the impact of commodity price fluctuations. However, we cannot always hedge the entire exposure of our operations from commodity price volatility.
Added
Access to Capital and Financing Our Credit Facility has substantial restrictions and financial covenants that may restrict our business and financing activities and our ability to pay distributions.
Removed
New trade policies, such as tariffs, could adversely affect our operations, costs, and business There is currently significant uncertainty regarding the future relationship between the United States and various other countries arising from changes that may be implemented by the new presidential administration, including with respect to trade policies, treaties, tariffs, taxes, and other limitations on cross-border operations.
Added
In October 2025, we amended the Credit Facility to extend the maturity date from October 31, 2027 to October 31, 2030 and remove the adjustment applied to secured overnight financing rate ("SOFR") loans.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeOur Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team” and, together with the VP IT, the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats.
Biggest changeOur Vice President, Information Technology (“VP IT”), with support from our Information Technology Infrastructure Team (“Infrastructure Team,” which, together with the VP IT, make up the “Cybersecurity Team”), has primary responsibility for the assessment and management of risks from cybersecurity threats.
Our VP IT, the Director of the Infrastructure Team, and our General Counsel make up the Information Security Committee, which has the initial responsibility for the assessment of and response to cybersecurity incidents consistent with our formal incident-response plan.
Our VP IT, the Director of our Infrastructure Team, and our General Counsel make up the Information Security Committee, which has the initial responsibility for the assessment of and response to cybersecurity incidents consistent with our formal incident-response plan.
We engage a third-party consultant to conduct external penetration testing at least annually. Our cybersecurity processes are adjusted as needed based on the results of these assessments. The assessment results are reported to the Audit Committee and Board, and our external auditor reviews our cybersecurity solutions and posture on at least an annual basis. 41 • Third-Party Risk Management .
We engage a third-party consultant to conduct external penetration testing at least annually. Our cybersecurity processes are adjusted as needed based on the results of these assessments. The assessment results are reported to the Audit Committee and Board, and our external auditor reviews our cybersecurity solutions and posture on at least an annual basis. • Third-Party Risk Management .
Collectively, the four members of the Cybersecurity Team have over 75 years of cybersecurity-related experience in both the private and public sectors, including perimeter and internal network security, secure email gateway, B2B and B2C eCommerce, on-premises and cloud storage environment security, and ransomware protection solutions.
Collectively, the four members of the Cybersecurity Team have over 75 years of cybersecurity-related experience in both the private and public sectors, including perimeter and 41 internal network security, secure email gateway, B2B and B2C eCommerce, on-premises and cloud storage environment security, and ransomware protection solutions.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeITEM 3. LEGAL PROCEEDINGS Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations. ITEM 4.
Biggest changeITEM 3. LEGAL PROCEEDINGS Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations. 42 ITEM 4.
MINE SAFETY DISCLOSURES Not applicable. 42 PART II
MINE SAFETY DISCLOSURES Not applicable. 43 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeCash Distribution Policy Our partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7.0% of the face amount of the preferred units per annum, through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter; and • second , to the holders of common units.
Biggest changeCash Distribution Policy Our partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7.0% of the face amount of the preferred units per annum, through November 27, 2023, then adjusting on November 28, 2023 and readjusting every two years thereafter, to a rate equal to the greater of (i) the rate in effect immediately prior to the relevant readjustment and (ii) the 10-year Treasury Rate as of such readjustment date plus 5.5% per annum (which rate adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025); and • second , to the holders of common units.
If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our Series B cumulative convertible preferred units are outstanding.” For a description of the relative rights and privileges of our Series B cumulative convertible preferred units to distributions, please read "Series B Cumulative Convertible Preferred Units" below. 44 Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy There is no guarantee that we will make cash distributions to our unitholders.
If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our Series B cumulative convertible preferred units are outstanding.” For a description of the relative rights and privileges of our Series B cumulative convertible preferred units to distributions, please read "Series B Cumulative Convertible Preferred Units" below. 45 Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy There is no guarantee that we will make cash distributions to our unitholders.
It is our intent, for at least the next several years, to finance most of our acquisitions and working interest capital needs with cash generated from operations, borrowings under our Credit Facility, our executed farmout agreements, and, in certain circumstances, proceeds from future equity and debt issuances.
It is our intent, for at least the next several years, to finance most of our acquisitions and working interest capital needs with cash generated from operations, borrowings under our Credit Facility, and, in certain circumstances, proceeds from future equity and debt issuances.
Any distributions paid on our common units with respect to a quarter will be paid within 60 days after the end of such quarter. 45 Series B Cumulative Convertible Preferred Units The holders of our Series B cumulative convertible preferred units were initially entitled to receive cumulative quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”).
Any distributions paid on our common units with respect to a quarter will be paid within 60 days after the end of such quarter. 46 Series B Cumulative Convertible Preferred Units The Series B cumulative convertible preferred units were initially entitled to quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”).
Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. As of February 21, 2025, we also had outstanding 14,711,219 Series B cumulative convertible preferred units.
Because many of our common units are held by brokers and other institutions on behalf of unitholders, we are unable to estimate the total number of unitholders represented by these holders of record. As of February 20, 2026, we also had outstanding 14,711,219 Series B cumulative convertible preferred units.
The graph assumes that the value of the investment in our common units was $100.00 on December 31, 2019.
The graph assumes that the value of the investment in our common units was $100.00 on December 31, 2020.
On November 28, 2023, the Distribution Rate was adjusted to 9.8% and will be readjusting every two years thereafter (each, a “Readjustment Date”).
The Distribution Rate adjusted on November 28, 2023, and will be readjusted every two years thereafter (each, a “Readjustment Date”).
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units are listed on the NYSE under the symbol “BSM.” As of February 21, 2025, there were 211,137,816 common units outstanding held by 361 holders of record.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES Our common units are listed on the NYSE under the symbol “BSM.” As of February 20, 2026, there were 212,333,793 common units outstanding held by 356 holders of record.
We cannot pay any distributions on any junior securities, including any of our common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions.
The Distribution Rate was adjusted to 9.8% effective November 28, 2023 and remained the same at 9.8% for November 28, 2025. We cannot pay any distributions on any junior securities, including common units, prior to paying the quarterly distribution payable to the preferred units, including any previously accrued and unpaid distributions.
Cumulative return is computed assuming reinvestment of distributions. 43 Comparison of Cumulative Total Return Assumes Initial Investment of $100 As of December 31, 2019 2020 2021 2022 2023 2024 Black Stone Minerals, L.P. $ 100.00 $ 57.04 $ 94.78 $ 168.59 $ 174.15 $ 171.39 S&P 500 Index 100.00 118.40 152.39 124.79 157.59 197.02 S&P Oil & Gas E&P Index 100.00 64.15 106.89 155.10 160.24 158.20 The information in this Annual Report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.
Cumulative return is computed assuming reinvestment of distributions. 44 Comparison of Cumulative Total Return Assumes Initial Investment of $100 As of December 31, 2020 2021 2022 2023 2024 2025 Black Stone Minerals, L.P. $ 100.00 $ 167.55 $ 303.23 $ 321.86 $ 326.69 $ 328.25 S&P 500 Index 100.00 128.71 105.40 133.10 166.40 196.16 S&P Oil & Gas E&P Index 100.00 167.58 244.21 253.58 251.80 246.96 The information in this Annual Report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Securities Exchange Act of 1934 ('the Exchange Act').
We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible at par value, equal to $20.39, within a 90-day period beginning on November 28, 2025, and each second anniversary thereafter. ITEM 6. RESERVED 46
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 during biennial 90-day windows. On August 21, 2025, we entered into an agreement with the holders of its Series B cumulative convertible preferred units.
Added
Under the agreement, we agreed not to exercise our redemption option, and the holders agreed to vote their preferred units in accordance with the recommendations of our Board of Directors on ordinary course matters and to certain customary transfer and standstill restrictions.
Added
These provisions remain in effect through November 27, 2027, with the next redemption window opening on November 28, 2027. ITEM 6. RESERVED 47

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

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Biggest changeOur computation of Adjusted EBITDA and Distributable cash flow may differ from computations of similarly titled measures of other companies. 51 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: Year Ended December 31, 2024 2023 (in thousands) Net income (loss) $ 271,326 $ 422,549 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 45,196 45,683 Interest expense 3,109 2,754 Income tax expense (benefit) 509 320 Accretion of asset retirement obligations 1,298 1,042 Equity-based compensation 8,564 10,829 Unrealized (gain) loss on commodity derivative instruments 50,944 (8,394) (Gain) loss on sale of assets, net — (73) Adjusted EBITDA 380,946 474,710 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (4) (9) Cash interest expense (2,030) (1,715) Preferred unit distributions (29,466) (21,776) Distributable cash flow $ 349,446 $ 451,210 52 Results of Operations Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2024 2023 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,606 3,757 (151) (4.0) % Natural gas (MMcf) 1 62,984 64,647 (1,663) (2.6) % Equivalents (MBoe) 14,103 14,532 (429) (3.0) % Equivalents/day (MBoe) 38.5 39.8 (1.3) (3.3) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 74.61 $ 76.74 $ (2.13) (2.8) % Natural gas ($/Mcf) 1 2.51 3.10 (0.59) (19.0) % Equivalents ($/Boe) $ 30.27 $ 33.62 $ (3.35) (10.0) % Revenue: Oil and condensate sales $ 269,061 $ 288,296 $ (19,235) (6.7) % Natural gas and natural gas liquids sales 1 157,907 200,297 (42,390) (21.2) % Lease bonus and other income 12,461 12,506 (45) (0.4) % Revenue from contracts with customers 439,429 501,099 (61,670) (12.3) % Gain (loss) on commodity derivative instruments (5,730) 91,117 (96,847) (106.3) % Total revenue $ 433,699 $ 592,216 $ (158,517) (26.8) % Operating expenses: Lease operating expense $ 9,705 $ 11,386 $ (1,681) (14.8) % Production costs and ad valorem taxes 49,577 56,979 (7,402) (13.0) % Exploration expense 2,735 2,148 587 27.3 % Depreciation, depletion, and amortization 45,196 45,683 (487) (1.1) % General and administrative 52,082 51,455 627 1.2 % Other expense: Interest expense $ 3,109 $ 2,754 $ 355 12.9 % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators.
Biggest changeOur computation of Adjusted EBITDA and Distributable Cash Flow may differ from computations of similarly titled measures of other companies. 53 The following table presents a reconciliation of net income (loss) to Adjusted EBITDA and Distributable Cash Flow for the periods indicated: Year Ended December 31, 2025 2024 (in thousands) Net income $ 299,932 $ 271,326 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 36,887 45,196 Interest expense 8,930 3,109 Income tax expense (benefit) (137) 509 Accretion of asset retirement obligations 1,374 1,298 Seismic data acquisition costs 17,349 2,287 Equity-based compensation 9,620 8,564 Unrealized (gain) loss on commodity derivative instruments (36,602) 50,944 Adjusted EBITDA 337,353 383,233 Adjustments to reconcile to Distributable Cash Flow: Change in deferred revenue (3) (4) Cash interest expense (7,845) (2,030) Preferred unit distributions (29,466) (29,466) Distributable Cash Flow $ 300,039 $ 351,733 54 Results of Operations Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2025 2024 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,259 3,606 (347) (9.6) % Natural gas (MMcf) 1 56,237 62,984 (6,747) (10.7) % Equivalents (MBoe) 12,632 14,103 (1,471) (10.4) % Equivalents/day (MBoe) 34.6 38.5 (3.9) (10.1) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 64.24 $ 74.61 $ (10.37) (13.9) % Natural gas ($/Mcf) 1 3.41 2.51 0.90 35.9 % Equivalents ($/Boe) $ 31.74 $ 30.27 $ 1.47 4.9 % Revenue: Oil and condensate sales $ 209,361 $ 269,061 $ (59,700) (22.2) % Natural gas and natural gas liquids sales 1 191,616 157,907 33,709 21.3 % Lease bonus and other income 21,351 12,461 8,890 71.3 % Revenue from contracts with customers 422,328 439,429 (17,101) (3.9) % Gain (loss) on commodity derivative instruments 47,591 (5,730) 53,321 (930.6) % Total revenue $ 469,919 $ 433,699 $ 36,220 8.4 % Operating expenses: Lease operating expense $ 10,141 $ 9,705 $ 436 4.5 % Production costs and ad valorem taxes 39,024 49,577 (10,553) (21.3) % Exploration expense 18,634 2,735 15,899 581.3 % Depreciation, depletion, and amortization 36,887 45,196 (8,309) (18.4) % General and administrative 55,463 52,082 3,381 6.5 % Other expense: Interest expense $ 8,930 $ 3,109 $ 5,821 187.2 % 1 As a mineral and royalty interest owner, we are often provided insufficient and inconsistent data on NGL volumes by our operators.
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.
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.
Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. 57 The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts.
Under this method, costs to acquire mineral and royalty interests and working interests in oil and natural gas properties, property acquisitions, successful exploratory wells, development costs, and support equipment and facilities are capitalized when incurred. The costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts.
Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2024 and 2023.
Actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including those set forth under “Cautionary Note Regarding Forward-Looking Statements” and “Part I, Item 1A. Risk Factors.” This discussion includes a comparison of our results of operations and liquidity and capital resources for 2025 and 2024.
Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts and costless collar contracts.
Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand. To manage the variability in cash flows associated with the projected sale of our oil and natural gas production, we use various derivative instruments, which have recently consisted of fixed-price swap contracts.
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 December 31, 2024 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.
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 December 31, 2025 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.
In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The following table shows the rig count at the end of each quarter presented: 2024 U.S.
In addition to drilling plans that we seek from our operators, we also monitor rig counts in an effort to identify existing and future leasing and drilling activity on our acreage. The following table shows the rig count at the end of each quarter presented: 2025 U.S.
Overview As of December 31, 2024, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells.
Overview As of December 31, 2025, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 71,000 producing wells.
We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2024 reserve report.
We are unable to predict future commodity prices with any greater precision than the futures market. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the commodity prices used in our December 31, 2025 reserve report.
We adjust our depletion rates semi-annually based upon the 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 expense decreased for the year ended December 31, 2024 as compared to 2023, primarily due to lower production volumes. General and administrative.
We adjust our depletion rates semi-annually based upon the 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 expense decreased for the year ended December 31, 2025 as compared to 2024, primarily due to lower production volumes. 56 General and administrative.
See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. As of December 31, 2024, we had not made any repurchases under the program.
See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information. As of December 31, 2025, we had not made any repurchases under the program.
Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash provided by operating activities for 2024 decreased as compared to 2023.
Our operating cash flows are dependent, in large part, on our production, realized commodity prices, derivative settlements, lease bonus revenue, and operating expenses. Cash provided by operating activities for 2025 decreased as compared to 2024.
General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services.
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.
Actual results could differ from those estimates. Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of oil and natural gas properties.
Actual results could differ from those estimates. Our consolidated financial statements are based on a number of significant estimates including oil and natural gas reserve quantities that are the basis for the calculations of depreciation, depletion, and amortization (“DD&A”) and impairment of proved oil and natural gas properties, if necessary.
For the year ended December 31, 2024, interest expense increased compared to 2023, primarily due to higher average outstanding borrowings under our Credit Facility. Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility.
For the year ended December 31, 2025, interest expense increased compared to 2024, primarily due to higher average outstanding borrowings under our Credit Facility. 57 Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility.
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 such period, calculated on a units-of-production basis. Estimates of proved developed producing reserves are a major component of the calculation of depletion.
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.
As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered.
As a non-operator, we have limited visibility into the timing of when new wells begin producing, and production statements may not be received for 30 to 90 days or more after production is delivered.
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 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.
For the discussion of changes from 2023 to 2022 and other financial information related to 2022, refer to Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2023 Annual Report on Form 10-K, which was filed with the SEC on February 20, 2024.
For the discussion of changes from 2024 to 2023 and other financial information related to 2023, refer to Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2024 Annual Report on Form 10-K, which was filed with the SEC on February 25, 2025.
Mineral and royalty interest production accounted for 95% and 94% of our natural gas volumes for the years ended December 31, 2024 and 2023, respectively. 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.
Mineral and royalty interest production accounted for 96% and 95% of our natural gas volumes for the years ended December 31, 2025 and 2024, respectively. 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.
Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility as applicable, 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").
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 distribution rate for the Series B cumulative convertible preferred units adjusted November 28, 2023 and will be readjusted every two years thereafter (each, a "Readjustment Date").
DD&A expense related to our producing oil and natural gas properties was $44.8 million, $45.0 million, and $47.2 million for the years ended December 31, 2024, 2023, and 2022, respectively. We evaluate impairment of producing properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
DD&A expense related to our producing oil and natural gas properties was $35.7 million, $44.8 million, and $45.0 million for the years ended December 31, 2025, 2024, and 2023, respectively. We evaluate impairment of producing and unproved properties whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable.
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.
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.
The decrease was primarily due to lower distributions paid to common unitholders partially offset by net borrowings under our Credit Facility in 2024 compared with net repayments in 2023. Development Capital Expenditures In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year.
The decrease was primarily due to lower distributions paid to unitholders and higher borrowings net of repayments under our Credit Facility in 2025 compared to 2024. Development Capital Expenditures In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year.
For the year ended December 31, 2024, production and ad valorem taxes decreased as compared to the year ended December 31, 2023, primarily due to a decrease in production taxes and processing and transportation costs stemming from lower commodity prices and decreased production volumes. Exploration expense.
For the year ended December 31, 2025, production and ad valorem taxes decreased as compared to the year ended December 31, 2024, primarily due to a decrease in production taxes and processing and transportation costs stemming from decreased production volumes, as well as lower ad valorem tax estimates. Exploration expense.
Our mineral and royalty interest oil and condensate volumes accounted for 95% and 94% of total oil and condensate volumes for the years ended December 31, 2024 and 2023, respectively. 53 Natural gas and natural gas liquids sales.
Our mineral and royalty interest oil and condensate volumes accounted for 96% and 95% of total oil and condensate volumes for the years ended December 31, 2025 and 2024, respectively. 55 Natural gas and natural gas liquids sales.
The EIA forecasts average exports of 14.1 Bcf per day for the start of 2025, an 18% increase from 2024 levels. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations in mid-2025. 49 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance.
The EIA forecasts average exports of 16.4 Bcf per day for the start of 2026, a 9% increase from 2025 levels. The EIA forecast reflects assumptions that U.S. LNG exports will increase as new LNG export projects begin operations in 2026. 50 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance.
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. Recent Developments Development Activity Currently, EXCO Resources, Inc. is operating one rig and Aethon is operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.
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. Recent Developments Development Activity During the fourth quarter, Aethon was operating three rigs on our Angelina, Nacogdoches, and San Augustine acreage in the Shelby Trough.
Natural gas and NGL sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes. The decrease in natural gas and NGL production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Haynesville/Bossier play trends.
Natural gas and NGL sales increased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to higher realized commodity prices partially offset by lower production volumes. The decrease in natural gas and NGL production was driven by decreased production volumes in the Austin Chalk and Haynesville/Bossier play trends.
The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025, at 1.9 Tcf, or 1% higher than the five-year average. The EIA expects inventories will rise to 3.7 Tcf at the end of October 2025, which would be 2% lower than the five-year average.
The EIA forecasts that inventories will conclude the withdraw al season, which is the end of March 2026, at 1.8 Tcf, or 2% higher than the five-year average. The EIA expects inventories will rise to 3.8 Tcf at the end of October 2026, which would be 5% higher than the five-year average.
Exploration expense typically consists of dry-hole expenses, payments for delay rentals where we are the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting. Exploration expense was higher in 2024 as compared to 2023, primarily due to an increase in seismic costs and delay rentals.
Exploration expense typically consists of dry-hole expenses, payments for delay rentals where we are the lessee, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.
See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
Expenditures related to drilling, completion, and recompletion costs for our non-operated working interests were $0.8 million and $4.2 million during 2024 and 2023, respectively. Additionally, we spent $3.4 million and $0.6 million acquiring leases in areas around our drilling programs during 2024 and 2023, respectively.
The timing, size, and nature of acquisitions are unpredictable. Expenditures related to drilling, completion, and recompletion costs for our non-operated working interests were $0.6 million and $0.8 million during 2025 and 2024, respectively. Additionally, we spent $11.1 million and $3.4 million acquiring leases in areas around our drilling programs during 2025 and 2024, respectively.
Acquisitions During 2024 we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs.
These acquisitions were considered asset acquisitions and were primarily located in East Texas, within the Haynesville expansion area. During 2024 we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $110.4 million, including capitalized direct transaction costs.
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.
Operating Expenses 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 slightly in 2025 as compared to 2024, due to higher nonrecurring service-related expenses, including workovers.
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 U.S. as measures of our financial performance.
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. 52 Adjusted EBITDA and Distributable Cash Flow have important limitations as analytical tools because they exclude some but not all items that affect net income (loss), the most directly comparable GAAP financial measure.
Applying this discount results in an approximate 1.5% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2024 reserve report prepared by NSAI.
Applying this discount results in an approximate 1% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2025 reserve report prepared by NSAI. Accrued Revenues We record revenue in the month production is delivered to the purchaser.
Asset Exchange In the third quarter of 2024, we closed on a transaction with a third-party operator whereby we received an oil and natural gas lease on approximately 8,000 net leasehold acres in East Texas in exchange for the assignment of approximately 51,000 undeveloped net mineral and royalty acres in Mississippi.
In March 2025, we closed on a transaction with a third-party operator whereby we acquired an oil and natural gas lease on approximately 2,900 net leasehold acres in East Texas in exchange for the assignment of approximately 900 undeveloped net mineral and royalty acres in Louisiana.
During 2024, we recognized $45.2 million of realized gains and $50.9 million of unrealized losses from our commodity derivatives, compared to $82.7 million of realized gains and $8.4 million of unrealized gains in 2023.
During 2025, we recognized $11.0 million of realized gains and $36.6 million of unrealized gains from our commodity derivatives, compared to $45.2 million of realized gains and $50.9 million of unrealized losses in 2024.
The following table reflects commodity prices at the end of each quarter presented: 2024 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 72.44 $ 68.75 $ 82.83 $ 83.96 Henry Hub spot natural gas ($/MMBtu) 1 $ 3.40 $ 2.65 $ 2.42 $ 1.54 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
The following table reflects commodity prices at the end of each quarter presented: 2025 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 57.26 $ 63.17 $ 66.30 $ 71.87 Henry Hub spot natural gas ($/MMBtu) 1 $ 4.00 $ 3.12 $ 3.26 $ 4.11 1 Source: EIA Rig Count As we are not the operator of record on any producing properties, drilling on our acreage is dependent upon the exploration and production companies that lease our acreage.
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.
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.
Revenue Total revenue for the year ended December 31, 2024 decreased compared to the year ended December 31, 2023. The decrease in total revenue from the corresponding period is due to lower oil and condensate sales, lower natural gas and NGL sales, and a loss on commodity derivative instruments in 2024 compared to a gain in 2023.
Revenue Total revenue for the year ended December 31, 2025 increased compared to the year ended December 31, 2024. The increase in total revenue from the corresponding period is due to higher natural gas and NGL sales, higher lease bonus and other income and a gain on commodity derivative instruments in 2025 compared to a loss in 2024.
As of December 31, 2024, we had hedged 77% and 24% of our available oil and condensate hedge volumes and 82% and 69% of our available natural gas hedge volumes for 2025 and 2026, respectively.
As of December 31, 2025, we had hedged 93% and 27% of our available oil and condensate hedge volumes and 100% and 54% of our available natural gas hedge volumes for 2026 and 2027, respectively.
As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates. Oil and Natural Gas Properties We follow the successful efforts method of accounting for oil and natural gas operations.
A significant decline in oil or natural gas prices could cause us to perform analyses to determine if our oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates. Oil and Natural Gas Properties We follow the successful efforts method of accounting for oil and natural gas operations.
Lease bonus income 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 was slightly lower for the year ended December 31, 2024, as compared to 2023.
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 was higher for the year ended December 31, 2025, as compared to 2024.
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 at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023.
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.
Leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays made up the majority of lease bonus and other income for 2024, while the majority of our 2023 lease bonus and other income came from leasing activity in the Haynesville/Bossier and Wolfcamp plays. Operating Expenses Lease operating expense.
Leasing activity in the Wolfcamp, Bakken/Three Forks, and Haynesville/Bossier plays made up the majority of lease bonus and other income for 2025, while the majority of our 2024 lease bonus and other income came from leasing activity in the Wolfcamp, Bakken/Three Forks, and Austin Chalk plays and proceeds from surface use waivers on our mineral acreage supporting solar development.
From time to time, such instruments may include variable-to-fixed-price swaps, fixed-price contracts, costless collars, and other contractual arrangements. The impact of these derivative instruments could affect the amount of revenue we ultimately realize. Our open derivative contracts consist of fixed-price swap contracts.
The impact of these derivative instruments could affect the amount of revenue we ultimately realize. 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.
We are allowed, but not required, to hedge up to 90% of such volumes for the first 24 months, 70% for months 25 through 36, and 50% for months 37 through 48.
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.
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.
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.
As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm. We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm.
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. 50 Hedging We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.
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.
We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of December 31, 2024, we were in compliance with all debt covenants. 56 See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
The next semi-annual redetermination is scheduled for April 2026. We are subject to various affirmative, negative, and financial maintenance covenants which pose limitations on future borrowings, leases, hedging, and sales of assets. As of December 31, 2025, we were in compliance with all debt covenants.
The unrealized losses on our commodity contracts in 2024 and the unrealized gains in 2023 were primarily driven by changes in the forward commodity price curves for natural gas. Lease bonus and other income . When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus.
The unrealized gains on our commodity contracts in 2025 were driven equally by changes in the forward commodity price curves for both natural gas and oil while the unrealized losses in 2024 were primarily driven by changes in the forward commodity price curves for natural gas. Lease bonus and other income .
Given the dynamic nature of these events, along with the geopolitical conflicts in Ukraine and the Middle East, we cannot reasonably estimate how long these market conditions will persist. While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.
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.
Cash Flows Year Ended December 31, 2024 Compared to Year Ended December 31, 2023 The following table shows our cash flows for the periods presented: Year Ended December 31, 2024 2023 Change (in thousands) Cash flows provided by operating activities $ 389,043 $ 521,251 $ (132,208) Cash flows used in investing activities (112,236) (19,740) (92,496) Cash flows used in financing activities (344,570) (435,536) 90,966 Operating Activities .
Cash Flows Year Ended December 31, 2025 Compared to Year Ended December 31, 2024 The following table shows our cash flows for the periods presented: Year Ended December 31, 2025 2024 Change (in thousands) Cash flows provided by operating activities $ 310,167 $ 389,043 $ (78,876) Cash flows used in investing activities (118,274) (112,236) (6,038) Cash flows used in financing activities (192,934) (344,570) 151,636 Operating Activities .
The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time. The amount of the borrowing base is redetermined semi-annually, usually in April and October. The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million.
The 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.
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.
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.
Oil and condensate sales. Oil and condensate sales decreased for the year ended December 31, 2024 as compared to the year ended December 31, 2023 due to lower realized commodity prices and lower production volumes. The decrease in oil and condensate production was driven by reduced production volumes in the Austin Chalk, Bakken/Three Forks, and Eagle Ford play trends.
Lower oil revenues, resulting from reduced production and commodity prices, partially offset the overall increase in total revenue. Oil and condensate sales. Oil and condensate sales decreased for the year ended December 31, 2025 as compared to the year ended December 31, 2024 due to lower realized commodity prices and lower production volumes.
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. During 2023 we acquired mineral and royalty interests for cash consideration of $14.6 million, including capitalized direct transaction costs.
Acquisitions Our current commercial strategy includes the continuation of meaningful, targeted mineral and royalty acquisitions to complement our existing positions. During 2025, we acquired mineral and royalty interests that consisted of primarily unproved oil and natural gas properties from various sellers for an aggregate of $114.5 million, including capitalized direct transaction costs.
For the year ended December 31, 2024, general and administrative expenses slightly increased compared to 2023, primarily due to increases in salaries, software related expenses, and consulting costs for internal projects; these costs were partially offset by a decrease in equity based compensation and expenses associated with the use of contractors.
For the year ended December 31, 2025, general and administrative expenses slightly increased compared to 2024, primarily due to higher salaries of $1.4 million driven by increased headcount and inflation, higher software-related expenses of $1.2 million, and higher equity-based compensation of $1.2 million.
The decrease in equity-based compensation was due to lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2024 compared to upward movements in our common unit price during 2023. 54 Other Expense Interest expense.
The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards driven by changes in our common unit price during 2025, compared to 2024. These increases were partially offset by a $0.6 million decrease in consulting costs for internal projects. Other Expense Interest expense.
The change was primarily due to increased acquisition activity in 2024 compared to the same period in 2023. Financing Activities . Cash flows used in financing activities for 2024 decreased as compared to 2023.
The increase was primarily due to higher additions to oil and natural gas properties leasehold costs in 2025 compared to the same period in 2024. Financing Activities . Net cash used in financing activities for 2025 decreased as compared to 2024.
The acquisitions were funded with cash from operating activities and were primarily located in the Gulf Coast land region. See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
These acquisitions were considered asset acquisitions and were primarily located in East Texas, within the Haynesville expansion area. See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information. Asset Exchange We completed multiple asset exchange transactions to consolidate a concentrated acreage position in East Texas.
Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 483 484 479 506 Natural gas 102 99 97 112 Other 4 4 5 3 Total 589 587 581 621 1 Source: Baker Hughes Incorporated 48 Natural Gas Storage A substantial portion of our revenue is derived from sales of oil production attributable to our interests; however, the majority of our production is natural gas.
Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 412 424 432 484 Natural gas 125 117 109 103 Other 9 8 6 5 Total 546 549 547 592 1 Source: Baker Hughes Incorporated 49 Natural Gas Storage The majority of the production volumes attributable to our interests is derived from natural gas production.
The difference between our estimates and the actual amounts received for oil and natural gas sales is recorded in the month that payment is received from the third party.
Differences between our estimates and the actual amounts received for oil and natural gas sales are recorded in the month that payment is received from the operator. We review historical production, pricing assumptions, and the accuracy of prior accruals to ensure that the recorded amounts appropriately reflect revenues expected to be collected.
If we have multiple contracts outstanding with a single counterparty, unless restricted by our agreement, we will net settle the contract payments. We may employ contractual arrangements other than fixed-price swap contracts in the future to mitigate the impact of price fluctuations.
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 subsequent redeterminations increased the borrowing base to $580.0 million in October 2023 and reaffirmed the borrowing base in April 2024 and November 2024. After each redetermination we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2025.
The amount of the borrowing base is redetermined semi-annually, usually in April and October. We reaffirmed the borrowing base in April 2024, November 2024 and April 2025 at $580.0 million.
The decrease was primarily due to a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue, and a decrease in cash received on settlements of commodity derivative instruments. 55 Investing Activities . Net cash used in investing activities for 2024 increased as compared to 2023.
The overall decrease was partially offset by higher natural gas and NGL sales due to higher realized natural gas prices in 2025 compared to the same period in 2024. 58 Investing Activities . Net cash used in investing activities for 2025 slightly increased as compared to 2024.
The following table shows natural gas storage volumes by region at the end of each quarter presented: 2024 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 745 846 660 363 Midwest 914 1,012 779 510 Mountain 262 283 239 162 Pacific 295 294 282 227 South Central 1,197 1,113 1,174 996 Total 3,413 3,548 3,134 2,258 1 Source: EIA Natural Gas Exports Net natural gas exports averaged 12.0 Bcf per day during 2024, a 1% increase from the 2023 average.
The following table shows natural gas storage volumes by region at the end of each quarter presented: 2025 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 736 832 602 284 Midwest 865 972 688 364 Mountain 264 269 228 165 Pacific 307 302 287 202 South Central 1,203 1,186 1,148 758 Total 3,375 3,561 2,953 1,773 1 Source: EIA Natural Gas Exports Net natural gas exports avera ged 15.0 Bcf per day during 2025, a 26% incr ea se from the 2024 average.
The carrying value of unproved properties, including unleased mineral rights, is determined based on management’s assessment of fair value using factors similar to those previously noted for proved properties, as well as geographic and geologic data. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss.
See "Note 6 - Fair Value Measurements" for additional information. Upon the sale of a complete depletable unit, the book value thereof, less proceeds or salvage value, is charged to income or loss.
Contractual Obligations The following table summarizes our minimum payments as of December 31, 2024 (in thousands): Payments due by period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years Credit facility $ 25,000 $ — $ 25,000 $ — $ — Operating lease obligations 2,041 1,436 573 32 — Purchase commitments 420 420 — — — Total $ 27,461 $ 1,856 $ 25,573 $ 32 $ — Critical Accounting Policies and Related Estimates The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP.
Critical Accounting Estimates The discussion and analysis of our financial condition and results of operations are based upon the consolidated financial statements, which have been prepared in accordance with GAAP.
As a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The expected sales volumes and prices for these properties are estimated and recorded within the Accounts receivable line item in the accompanying consolidated balance sheets.
As a result, a portion of revenue for each period is accrued and recorded in the line item Accrued revenue and accounts receivable on the consolidated balance sheets. 61 Accrued revenues are estimated using historical production data, adjusted for expected production declines, and projected sales prices, including applicable pricing adjustments.
Removed
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.
Added
Aethon’s development program remains on track, with 6 wells spud in the second half of 2025 as part of the current program year ending June 30, 2026, an additional 8 wells expected in the first half 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.
Removed
During 2025, Aethon has already turned-to-sales (“TTS”) 11 gross (0.9 net) wells with early data showing better performance than the older offsets and initial rates primarily between 20 – 30 MMcf/d. We expect Aethon to continue its development program under the amended JEAs with an estimated 17 gross (1.1 net) additional wells TTS during 2025.
Added
Aethon successfully turned to sales 7 gross (0.42 net) wells during the fourth quarter and has an inventory of 5 gross (0.31 net) wells from the previous program year that it expects to turn to sales during early 2026. Our agreement with Revenant covers 270,000 gross acres in which we currently control approximately 122,000 undeveloped net acres.
Removed
In the Louisiana Haynesville during 2024, we entered into several Accelerated Drilling Agreements (“ADAs”) with large, well-capitalized operators. Under these agreements, the operators will provide near term certainty and accelerated development on our high-interest areas in exchange for a reduced royalty burden.
Added
Revenant is obligated to drill a minimum of 6 wells in 2026, increasing annually to a minimum of 25 wells per year by 2030. We also secured a non-operated working interest partner for the development.
Removed
During 2024, 2 gross (0.4 net) wells were TTS and we expect an additional 11 gross (0.6) net wells to TTS in 2025. In the Permian Basin, a large producer is expected to begin development of over 37 gross (1.3 net) wells in Culberson County, Texas, which includes 8 gross wells to be TTS in the fourth quarter of 2025.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeDuring the twelve months ended December 31, 2024, we had weighted average outstanding borrowings under our Credit Facility of $7.7 million, bearing interest at a weighted-average interest rate of 7.5%.
Biggest changeDuring the year ended December 31, 2025, we had $95.8 million weighted average outstanding borrowings under our Credit Facility, bearing interest at a weighted-average interest rate of 7.03%.
The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable. Interest Rate Risk We have exposure to changes in interest rates on our indebtedness.
The inability or failure of our significant operators to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. However, we believe the credit risk associated with our operators and customers is acceptable. 62 Interest Rate Risk We have exposure to changes in interest rates on our indebtedness.
To reduce the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative financial instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.
To mitigate the impact of fluctuations in oil and natural gas prices on our revenues, we use commodity derivative financial instruments to reduce our exposure to price volatility of oil and natural gas. The counterparties to the contracts are unrelated third parties.
Commodity prices have been historically volatile based upon the dynamics of supply and demand. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the twelve months ended December 31, 2024.
Commodity prices have been historically volatile based upon the dynamics of supply and demand. To estimate the effect lower prices would have on our reserves, we applied a 10% discount to the SEC commodity pricing for the twelve months ended December 31, 2025.
Prices for oil, natural gas, and NGLs have been volatile for several years, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.
Prices for oil, natural gas, and NGLs have been volatile, and we expect this unpredictability to continue in the future. The prices that our operators receive for production depend on many factors outside of our or their control.
Applying this discount results in an approximate 1.5% reduction of proved reserve volumes as compared to the undiscounted December 31, 2024 SEC pricing scenario. Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
Applying this discount results in an approximate 1% reduction of proved reserve volumes as compared to the undiscounted December 31, 2025 SEC pricing scenario. Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of less than $0.1 million for the year ended December 31, 2024, assuming that our indebtedness remained constant throughout the period.
The impact of a 1% increase in the interest rate on this amount of debt would have resulted in an increase in interest expense, and a corresponding decrease in our results of operations, of $1.0 million for the year ended December 31, 2025, assuming that our indebtedness remained constant throughout the period.
As of December 31, 2024, we had seven counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under our Credit Facility. 59 Our principal exposure to credit risk results from receivables generated by the production activities of our operators.
As of December 31, 2025, we had eight counterparties, all of which are rated Baa2 or better by Moody’s and are lenders under our Credit Facility. Our principal exposure to credit risk results from receivables generated by the production activities of our operators.
Added
Based upon our open commodity derivative positions at December 31, 2025, a hypothetical $1 per barrel increase or decrease in the NYMEX WTI strip price would result in an increase or decrease of approximately $3.4 million in the fair value of our oil derivative contracts.
Added
Similarly, a hypothetical $0.10 per MMBtu increase or decrease in the NYMEX Henry Hub natural gas strip price would result in an increase or decrease of approximately $7.7 million in the fair value of our natural gas derivative contracts. These hypothetical changes in fair value could result in a gain or loss depending on whether commodity prices increase or decrease.

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