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What changed in Black Stone Minerals, L.P.'s 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of Black Stone Minerals, L.P.'s 2023 and 2024 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 2024 report.

+193 added−208 removedSource: 10-K (2025-02-25) vs 10-K (2024-02-20)

Top changes in Black Stone Minerals, L.P.'s 2024 10-K

193 paragraphs added · 208 removed · 159 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

81 edited+16 added−20 removed213 unchanged
Biggest change“Business and Properties — Environmental Matters” for an additional description of some of the many ESG-related developments that may affect us, our operators, and/or the oil and gas sector more generally. 32 Additionally, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
Biggest change“Business and Properties — Environmental Matters” for additional information on related developments that may affect us, our operators, and/or the oil and gas sector more generally.
The changes in the price of oil have been caused by many factors, including periods of 24 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 fluctuations in demand as a result of the COVID-19 pandemic.
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.
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.
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.
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.
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.
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.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could increase costs or eliminate or postpone certain tax deductions that currently are available to us or 37 our services providers with respect to oil and gas development.
The passage of any legislation as a result of these proposals or any similar changes in U.S. federal income tax laws could increase costs or eliminate or postpone certain tax deductions that currently are available to us or our services providers with respect to oil and gas development.
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.
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.
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.
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.
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.
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.
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.
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.
Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of oil production, transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand.
Our or our operators’ access to transportation options and the prices we or our operators receive can also be affected by federal and state regulation—including regulation of production, transportation, and pipeline safety—as well by general economic conditions and changes in supply and demand.
In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders. 35 The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.
In addition, borrowings by us do not constitute a breach of any duty owed by our general partner to our unitholders. The market price of our common units could be adversely affected by sales of substantial amounts of our common units in the public or private markets.
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.
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.
Relatedly, 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.
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.
To date, we have financed capital 29 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, executed farmout agreements, and the issuance of equity securities.
Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, 30 plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation.
Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation.
The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions.
The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions.
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, 2023 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, 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.
There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices.
There has been controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic-fracturing practices.
"Business and properties — Environmental Matters — Hydraulic Fracturing" for a description of the laws and regulations that affect our 31 operators and that may affect us.
"Business and properties — Environmental Matters — Hydraulic Fracturing" for a description of the laws and regulations that affect our operators and that may affect us.
Our estimates of proved reserves and related valuations as of December 31, 2023, 2022, and 2021 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, 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.
For the year ended December 31, 2023, 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, 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.
Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil production and have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
Any significant curtailment in gathering system or transportation, processing, or refining-facility capacity could reduce our or our operators’ ability to market oil and natural gas production and have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.
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. Increasing 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. Increased attention to environmental, social and governance (ESG) matters may impact our business.
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, 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; • 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, the 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; 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.
The estimates of reserves as of December 31, 2023, 2022, and 2021 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, 2023, 2022, and 2021, respectively, in accordance with the SEC guidelines applicable to reserve 26 estimates for those periods.
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.
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. 41
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.
In January 2024, the Biden administration announced that approvals for pending and future applications for certain new LNG facilities were being paused pending a review by the DOE that aims to assess whether climate effects should be more heavily considered in the authorization process for such LNG export projects.
In January 2024, the Biden administration announced that approvals for pending and future applications for certain new LNG facilities were being paused pending a review by the Department of Energy ("DOE") that aims to assess whether climate effects should be more heavily considered in the authorization process for such LNG export projects.
Increasing 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.
Increasing attention to, and social expectations on, companies to address climate change and other environmental and social impacts, investor and societal explanations 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 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.
By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement is governed by Delaware law.
Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions. By purchasing a common unit, a limited partner is irrevocably consenting to these provisions regarding claims, suits, actions, or proceedings, and submitting to the exclusive jurisdiction of Delaware courts. Our partnership agreement is governed by Delaware law.
Approximately 41% of our 2023 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 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.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in BSMC prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by us or any conversion of the Series B cumulative convertible preferred units at our option or in connection with a change of control may not vote on any matter. 34 Our partnership agreement includes exclusive forum, venue, and jurisdiction provisions.
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 15% or more of any class of units then outstanding, other than the limited partners in our predecessor prior to the IPO, their transferees, persons who acquired such units with the prior approval of the Board, holders of Series B cumulative convertible preferred units in connection with any vote, consent or approval of the Series B cumulative convertible preferred units as a separate class, and persons who own 15% or more of any class as a result of any redemption or purchase of any other person's units or similar action by us or any conversion of the Series B cumulative convertible preferred units at our option or in connection with a change of control may not vote on any matter.
You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income. Tax gain or loss on the disposition of our common units could be more or less than expected.
You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability that results from that income. Tax gain or loss on the disposition of our common units could be more or less than expected.
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. Approximately 59% of our 2023 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. 23 Approximately 63% of our 2024 oil and natural gas revenues were derived from oil and condensate sales.
Finally, public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits.
Additionally, certain public statements with respect to ESG matters, such as emissions reduction goals, other environmental targets, or other commitments addressing certain social issues, have been subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” i.e., misleading information or false claims overstating potential ESG benefits.
Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate-related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations of requirements of financial institutions.
Any new laws or regulations imposing requirements on our business related to the disclosure of climate-related risks may result in reputational harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations of requirements of financial institutions.
During the ten years prior to December 31, 2023, 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 29, 2023, the last trading day of 2023, the WTI spot market price of oil was $71.89.
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.
It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own our common units, adversely affecting the market price of our common units. Oil and natural gas operations are subject to various governmental laws and regulations, including those directed at the threat of climate change.
It is also possible that the concerns about the production and use of fossil fuels will reduce the number of investors willing to own our common units, adversely affecting the market price of our common units. Oil and natural gas operations are subject to various governmental laws and regulations.
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, 2023, we had no outstanding borrowings and the aggregate maximum credit amounts of the lenders were $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, 2024, we had $25.0 million outstanding borrowings a nd the aggregate maximum credit amounts of the lenders wer e $1.0 billion.
Although we expect most of our income to qualify for this deduction, application of these rules to income from mineral interests, such as royalty income, is not entirely clear. The IRS may challenge our treatment of royalty income as qualifying for the deduction.
Although we expect most of our income to qualify for this deduction, application of these rules to income from mineral interests, such as royalty income, is not entirely clear.
Any 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.
Any 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.
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.
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.
Our borrowing base determined by the lenders under our Credit Facility in October 2023 was $580.0 million and we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2024. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings.
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.
Additionally, institutional lenders may decide not to provide funding for fossil fuel energy companies or the corresponding infrastructure projects based on climate change related concerns, which could affect our access to capital for potential growth projects.
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.
During the ten years prior to December 31, 2023, natural gas prices at Henry Hub have ranged from a high of $23.86 per MMBtu in 2021 to a low of $1.33 per MMBtu in 2020. On December 29, 2023, the last trading day of 2023, the Henry Hub spot market price of natural gas was $2.58 per MMBtu.
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 $3.40 per MMBtu.
These mineral servitudes, once created, are subject to a ten-year prescription of nonuse. During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner.
During the ten-year period, the mineral-servitude owner has to conduct good-faith operations on the servitude for the discovery and production of minerals, or the mineral servitude “prescribes,” and the mineral rights associated with that servitude revert to the surface owner.
Year Ended December 31, 2023 During the Five Years Prior to 2023 As of December 31, High Low High 2 Low 3 2023 2022 2021 WTI spot crude oil ($/Bbl) 1 $ 93.67 $ 66.61 $ 123.64 $ 8.91 $ 71.89 $ 80.16 $ 75.33 Henry Hub spot natural gas ($/MMBtu) 1 3.78 1.74 23.86 1.33 2.58 3.52 3.82 1 Source: EIA 2 High prices for WTI and Henry Hub were in 2022 and 2021, respectively. 3 Low prices for WTI and Henry Hub were in 2020.
Year Ended December 31, 2024 During the Five Years Prior to December 31, 2024 As of December 31, High Low High 2 Low 3 2024 2023 2022 WTI spot crude oil ($/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.
Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS 39 challenge to those positions could adversely affect the amount of tax benefits available to you.
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 operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash distributions to our unitholders.
The operators may elect not to undertake development activities, or may undertake these activities in an unanticipated fashion, which may result in significant fluctuations in our results of operations and cash distributions to our unitholders. Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders.
Key Persons We rely on a few key individuals whose absence or loss could adversely affect our business. Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business.
Many key responsibilities within our business have been assigned to a small number of individuals. The loss of their services could adversely affect our business.
Our partnership agreement does not require us to pay any distributions at all on our common units. If we make distributions, our Series B cumulative convertible 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.
If we make distributions, our Series B cumulative convertible 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.
Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment or other industries which could have a negative impact on our unit price and/or our access to and costs of capital.
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.
Such agency action could also increase the potential for private litigation. Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims. Non-compliance with these new laws may result in the imposition of substantial fines or penalties. Other states are considering similar laws.
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.
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.
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.
As of December 31, 2023, we had 209,991,223 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
As of December 31, 2024, we had 210,694,933 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
Thus, you may recognize 38 both ordinary income and capital loss from the sale of your common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units.
Thus, you may recognize both ordinary income and capital loss from the sale of your common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.
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 business income".
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.
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.
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.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. 36 Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy the “qualifying income” requirement within Section 7704(d)(1)(E) of the Internal Revenue Code.
Despite the fact that we are organized as a limited partnership under Delaware law, we will be treated as a corporation for U.S. federal income tax purposes unless we satisfy the “qualifying income” requirement within Section 7704(d)(1)(E) of the Internal Revenue Code. Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement.
Based upon our current operations and current Treasury Regulations, we believe that we satisfy the qualifying income requirement. However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us. The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves.
Our proved undeveloped reserves may not be developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations, and the decision to pursue development of a proved undeveloped drilling location will be made by the operator and not by us.
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. A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation.
A mineral servitude is created in Louisiana when the mineral rights are separated from the ownership of the surface, whether by sale or reservation. These mineral servitudes, once created, are subject to a ten-year prescription of nonuse.
Failure to make the required repayment could result in a default under our Credit Facility, which could materially adversely affect our business, financial condition, results of operations, and distributions to our unitholders. 28 The operating and financial restrictions and covenants in our Credit Facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage in, expand, or pursue our business activities, or pay distributions.
The operating and financial restrictions and covenants in our Credit Facility restrict, and any future financing agreements likely will restrict, our ability to finance future operations or capital needs, engage in, expand, or pursue our business activities, or pay distributions.
In December 2023, we received notice that Aethon Energy (“Aethon”) was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas.
In December 2023, we received notice that Aethon was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas. In September 2024, we entered into letter agreements with Aethon to amend the joint exploration agreements to, among other things, withdraw the invocation of the time-out provisions.
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.
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.
Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us. These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.
Please read Part I, Items 1 and 2. “Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us.
If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations, and cash distributions to unitholders may be adversely affected. 25 The unavailability, high cost, or shortages of rigs, equipment, raw materials, supplies, or personnel may restrict or result in increased costs for operators related to developing and operating our properties.
If the wells in the process of being completed do not produce sufficient revenues or if dry holes are drilled, our financial condition, results of operations, and cash distributions to unitholders may be adversely affected.
Although our counsel has advised us that under current law our royalty income should qualify for the deduction, 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 We have and will continue to incur increased costs as a result of being a publicly traded partnership.
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.
We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of the development will be as estimated.
The reserve data included in the reserve report of our engineer assume that substantial capital expenditures are required to develop the reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that development will occur as scheduled, or that the results of the development will be as estimated.
If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed.
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.
In 2023, we generated 10% of our royalty revenues and 19% 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. Only one of these operators has an active drilling program on this acreage.
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.
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 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.
In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells. If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer.
If our operators are unable to secure a sufficient number of drilling rigs at reasonable costs, our financial condition and results of operations could suffer.
In addition, any alleged claims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory focus and scrutiny.
Any alleged claims of greenwashing against us or others in our industry may lead to increased litigation risks and foster negative sentiment and diversion of investments.
The oil and natural gas industry is cyclical, which can result in shortages of drilling rigs, equipment, raw materials, supplies, and personnel. When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand.
When shortages occur, the costs and delivery times of rigs, equipment, and supplies increase and demand for, and wage rates of, qualified drilling rig crews also rise with increases in demand. In accordance with customary industry practice, our operators rely on independent third-party service providers to provide many of the services and equipment necessary to drill new wells.
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.
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.
If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss. 33 Risks to Unitholders under Our Partnership Agreement The Board may modify or revoke our cash distribution policy at any time at its discretion.
Additionally, undeveloped acreage has greater risk of title defects than developed acreage. If there are any title defects or defects in assignment of leasehold rights in properties in which we hold an interest, we will suffer a financial loss.
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.
Our partnership agreement restricts the potential liability of our general partner and its directors and executive officers to our unitholders.
“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments.” If any of these risks are realized, production may decrease, reducing cash generated from operations and cash available for distribution.
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.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeWe also ensure SOC-1 or SOC-2 compliance for our third party providers, including our banking, payroll, and stock-plan administration relationships. 42 While we and our service providers have experienced cybersecurity incidents in the past, as of the date of this Report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us, including our business strategy, results of operation, or financial condition.
Biggest changeWhile we and our service providers have experienced cybersecurity incidents in the past, as of the date of this Annual Report, we are not aware of any previous cybersecurity threats that have materially affected or are reasonably likely to materially affect us, including our business strategy, results of operation, or financial condition.
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 .
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 .
In addition, members of the Cybersecurity Team have multiple network-security certifications relevant to the technologies we deploy. Our Board of Directors provides oversight over our enterprise-wide risk management, which includes cybersecurity risk-management, and the Audit Committee assists the Board with oversight of cybersecurity matters.
In addition, members of the Cybersecurity Team have multiple network-security certifications relevant to the technologies we deploy. Our Board of Directors provides oversight of our enterprise-wide risk management, which includes cybersecurity risk-management, and the Audit Committee assists the Board with oversight of cybersecurity matters.
Our VP IT, the Manager 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 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.
The VP IT reports on cybersecurity matters to senior management regularly and to the Audit Committee at least annually, and more often if needed. The Audit Committee, in turn, makes periodic reports to the Board on relevant cybersecurity matters.
The VP IT reports on cybersecurity matters to senior management on a regular basis and to the Audit Committee at least annually, and more often if needed. The Audit Committee, in turn, makes periodic reports to the Board on relevant cybersecurity matters.
We refer to industry standards, such as those issued by NIST and ISO, as part of our efforts to maintain best practices across our environment and we use various cybersecurity tools and processes designed to manage cybersecurity threats including network and systems authentication, network and infrastructure architecture security, endpoint security, and operating system patching. • Third-Party Network Security Assessments.
We refer to industry standards, such as those issued by National Institutes of Standards and Technology ("NIST") and International Organization for standardization ("ISO"), as part of our efforts to maintain best practices across our environment and we use various cybersecurity tools and processes designed to manage cybersecurity threats including network and systems authentication, network and infrastructure architecture security, endpoint security, and operating system patching. • Third-Party Network Security Assessments.
We conduct information-security assessments before allowing sensitive data to be hosted by third parties.
We conduct information-security assessments before allowing sensitive data to be hosted by third parties. We also ensure SOC-1 or SOC-2 compliance for our third party providers, including our banking, payroll, and stock-plan administration relationships.

Item 3. Legal Proceedings

Legal Proceedings — active lawsuits and investigations

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Biggest changeMINE SAFETY DISCLOSURES Not applicable. 43 PART II
Biggest changeMINE SAFETY DISCLOSURES Not applicable. 42 PART II

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeThereafter, we may redeem the preferred units at par value, equal to $20.39, within a 90-day period on each second anniversary following November 28, 2023. ITEM 6. RESERVED 47
Biggest changeWe 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
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.
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.
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 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. 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”).
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 16, 2024, 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 21, 2025, 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, 2018.
The graph assumes that the value of the investment in our common units was $100.00 on December 31, 2019.
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 16, 2024, there were 210,313,477 common units outstanding held by 368 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 21, 2025, there were 211,137,816 common units outstanding held by 361 holders of record.
Cumulative return is computed assuming reinvestment of distributions. 44 Comparison of Cumulative Total Return Assumes Initial Investment of $100 As of December 31, 2018 2019 2020 2021 2022 2023 Black Stone Minerals, L.P. $ 100.00 $ 90.20 $ 51.09 $ 84.40 $ 149.18 $ 153.17 S&P 500 Index 100.00 131.49 155.68 200.37 164.08 207.21 S&P Oil & Gas E&P Index 100.00 90.56 58.06 96.72 140.31 144.91 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. 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.
Removed
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 until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value.

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. 52 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, 2023 2022 (in thousands) Net income (loss) $ 422,549 $ 476,480 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 45,683 47,804 Interest expense 2,754 6,286 Income tax expense (benefit) 320 58 Accretion of asset retirement obligations 1,042 861 Equity-based compensation 10,829 17,388 Unrealized (gain) loss on commodity derivative instruments (8,394) (82,486) (Gain) loss on sale of assets, net (73) (17) Adjusted EBITDA 474,710 466,374 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (9) (30) Cash interest expense (1,715) (4,282) Preferred unit distributions (21,776) (21,000) Distributable cash flow $ 451,210 $ 441,062 53 Results of Operations Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2023 2022 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,757 3,591 166 4.6 % Natural gas (MMcf) 1 64,647 59,778 4,869 8.1 % Equivalents (MBoe) 14,532 13,554 978 7.2 % Equivalents/day (MBoe) 39.8 37.1 2.7 7.3 % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 76.74 $ 93.65 $ (16.91) (18.1) % Natural gas ($/Mcf) 1 3.10 7.28 (4.18) (57.4) % Equivalents ($/Boe) $ 33.62 $ 56.90 $ (23.28) (40.9) % Revenue: Oil and condensate sales $ 288,296 $ 336,287 $ (47,991) (14.3) % Natural gas and natural gas liquids sales 1 200,297 434,945 (234,648) (53.9) % Lease bonus and other income 12,506 13,052 (546) (4.2) % Revenue from contracts with customers 501,099 784,284 (283,185) (36.1) % Gain (loss) on commodity derivative instruments 91,117 (120,680) 211,797 (175.5) % Total revenue $ 592,216 $ 663,604 $ (71,388) (10.8) % Operating expenses: Lease operating expense $ 11,386 $ 12,380 $ (994) (8.0) % Production costs and ad valorem taxes 56,979 66,233 (9,254) (14.0) % Exploration expense 2,148 193 1,955 1013.0 % Depreciation, depletion, and amortization 45,683 47,804 (2,121) (4.4) % General and administrative 51,455 53,652 (2,197) (4.1) % Other expense: Interest expense 2,754 6,286 (3,532) (56.2) % 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. 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.
The price we receive for natural gas is tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies.
The price we receive for natural gas is tied to 58 a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality and heat content of natural gas, and prevailing supply and demand conditions, so that the price of natural gas fluctuates to remain competitive with other available natural gas supplies.
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 2023 and 2022.
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.
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. 51 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. 50 Hedging We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.
The timing, size, and nature of acquisitions are unpredictable. Our 2024 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest.
The timing, size, and nature of acquisitions are unpredictable. Our 2025 capital expenditure budget associated with our non-operated working interests is expected to be approximately $2.3 million. The majority of this capital is anticipated to be spent on workovers and recompletions on existing wells in which we own a working interest.
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, 2023 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, 2024 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: 2023 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: 2024 U.S.
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, 2023 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, 2024 reserve report.
Given the dynamic nature of these events, along with the volatile geopolitical conflicts in Ukraine, 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.
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.
For the discussion of changes from 2022 to 2021 and other financial information related to 2021, refer to Part II, Item 7. "Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2022 Annual Report on Form 10-K, which was filed with the SEC on February 22, 2023.
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.
Overview As of December 31, 2023, our mineral and royalty interests were located in 41 states in the continental United States including all of the major onshore producing basins. These non-cost-bearing interests include ownership in approximately 68,000 producing wells.
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.
DD&A expense related to our producing oil and natural gas properties was $45.0 million, $47.2 million, and $60.4 million for the years ended December 31, 2023, 2022, and 2021, 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 $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.
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 2023 increased as compared to 2022.
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.
The increase was primarily due to higher distributions paid to common unitholders partially offset by lower net repayments under our Credit Facility in 2023 compared with 2022. 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 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.
As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606.
As each unit of product represents a separate performance obligation and the consideration is variable as it relates to oil and natural gas prices, we recognize revenue from oil and natural gas sales using the practical expedient for variable consideration in ASC 606. We record oil and natural gas revenue in the month production is delivered to the purchaser.
Applying this discount results in an approximate 2.0% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2023 reserve report prepared by NSAI.
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.
Lease operating expense decreased in 2023 as compared to 2022, primarily due to a reduction in variable costs as a result of lower production from our non-operated working interest properties. Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities.
Lease operating expense decreased in 2024 as compared to 2023, due to a reduction in variable costs as a result of lower production from our non-operated working interest properties and lower nonrecurring service-related expenses, including workovers. Production costs and ad valorem taxes. Production taxes include statutory amounts deducted from our production revenues by various state taxing entities.
The April 2023 borrowing base redetermination reaffirmed the borrowing base at $550.0 million and the October 2023 borrowing base redetermination increased the borrowing base to $580.0 million. After both redeterminations we elected to maintain cash commitments at $375.0 million. The next semi-annual redetermination is scheduled for April 2024.
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.
See "Note 14 – Common Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
See "Note 12 – Preferred Units" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
Our mineral 54 and royalty interest oil and condensate volumes accounted for 94% and 93% of total oil and condensate volumes for each of the years ended December 31, 2023 and 2022, respectively. Natural gas and natural gas liquids sales.
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.
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 and costless collar contracts.
During 2023, we recognized $82.7 million of realized gains and $8.4 million of unrealized gains from our commodity derivatives, compared to $203.2 million of realized losses and $82.5 million of unrealized gains in 2022.
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 $8.4 million of unrealized gains in 2023.
The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2024, at 1.9 Tcf, or 15% higher than the five-year average. The EIA expects inventories will rise to 4.0 Tcf at the end of October 2024, which would be 6% higher than the five-year average.
The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2025, at 1.9 Tcf, or 1% higher than the five-year average. The EIA expects inventories will rise to 3.7 Tcf at the end of October 2025, which would be 2% lower than the five-year average.
The following table reflects commodity prices at the end of each quarter presented: 2023 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 71.89 $ 90.77 $ 70.66 $ 75.68 Henry Hub spot natural gas ($/MMBtu) 1 $ 2.58 $ 2.68 $ 2.48 $ 2.10 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: 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.
As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. Prior-period performance obligations We record oil and natural gas revenue in the month production is delivered to the purchaser.
As we have determined that each unit of product generally represents a separate performance obligation, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.
In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period. The changes in fair value result from new positions and settlements that may occur during each reporting period, as well as the relationships between contract prices and the associated forward curves.
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.
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.
The change was primarily due to increased acquisition activity and higher net oil and natural gas capital expenditures in 2023 compared to the same period in 2022. Financing Activities . Cash flows used in financing activities for 2023 increased as compared to 2022.
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.
Revenues from Contracts with Customers Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. 59 Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured.
Revenues from Contracts with Customers Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified.
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. As of December 31, 2023, we had hedged 73% of our available oil and condensate hedge volumes and 66% of our available natural gas hedge volumes for 2024.
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.
The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate. There was no impairment of proved oil and natural gas properties for the years ended December 31, 2023, 2022, and 2021.
The factors used to determine fair value include estimates of proved reserves, future commodity prices, timing of future production, operating costs, future capital expenditures, and a risk-adjusted discount rate.
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, 2023, we were in compliance with all debt covenants.
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.
See "Note 8 – Credit Facility" to the consolidated financial statements included elsewhere in this Annual Report for additional information. 57 Contractual Obligations The following table summarizes our minimum payments as of December 31, 2023 (in thousands): Payments due by period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years Operating lease obligations $ 2,463 $ 655 $ 1,764 $ 44 $ — Purchase commitments 660 450 205 5 — Total $ 3,123 $ 1,105 $ 1,969 $ 49 $ — 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.
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.
Revenue Total revenue for the year ended December 31, 2023 decreased compared to the year ended December 31, 2022. The decrease in total revenue from the corresponding period is primarily due to lower realized commodity prices partially offset by an increase in production volumes and a gain on commodity derivative instruments in 2023 compared to a loss in 2022.
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.
The unrealized gains on our commodity contracts in 2023 were primarily driven by changes in the forward commodity price curves for natural gas and in 2022 by changes in the forward commodity price curves for both oil and natural gas. Lease bonus and other income .
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.
Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.
Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured. Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.
The overall increase was partially offset by a decrease in oil and condensate sales revenue and natural gas and NGL sales revenue due to lower realized commodity prices. 56 Investing Activities . Net cash used in investing activities for 2023 increased as compared to 2022.
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.
Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 500 502 545 592 Natural gas 120 116 124 160 Other 2 5 5 3 Total 622 623 674 755 1 Source: Baker Hughes Incorporated 49 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 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.
Natural gas and NGL sales decreased for the year ended December 31, 2023 as compared to the year ended December 31, 2022 due to lower realized commodity prices offset by higher production volumes.
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.
For the year ended December 31, 2023, general and administrative expenses decreased compared to 2022, primarily due to a $6.6 million decrease in equity-based compensation from lower costs recognized for performance-based incentive awards resulting from downward movements in our common unit price during 2023 compared to upward movements in our 55 common unit price during 2022.
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 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. For the years ended December 31, 2023 and 2022, revenue recognized in the reporting periods related to performance obligations satisfied in prior reporting periods was immaterial.
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.
Cash Flows Year Ended December 31, 2023 Compared to Year Ended December 31, 2022 The following table shows our cash flows for the periods presented: Year Ended December 31, 2023 2022 Change (in thousands) Cash flows provided by operating activities $ 521,251 $ 424,983 $ 96,268 Cash flows provided by (used in) investing activities (19,740) (1,215) (18,525) Cash flows provided by (used in) financing activities (435,536) (428,337) (7,199) Operating Activities .
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 .
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. There was no impairment of unproved properties for the years ended December 31, 2023, 2022, and 2021.
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.
Credit Facility We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion. The commitment of the lenders equals the least of the aggregate maximum credit amount, the then-effective borrowing base, and the aggregate elected commitment, as it may be adjusted from time to time.
Credit Facility We maintain a senior secured revolving credit agreement, as amended, (the “Credit Facility”). The Credit Facility has an aggregate maximum credit amount of $1.0 billion and terminates on October 31, 2027.
The acquisitions were funded with cash from operating activities 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. We had no material acquisition activity during 2022.
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.
For the year ended December 31, 2023, production and ad valorem taxes decreased as compared to the year ended December 31, 2022, as a result of lower commodity prices. Exploration expense. Exploration expense typically consists of dry-hole expenses, delay rentals, and geological and geophysical costs, including seismic costs, and is expensed as incurred under the successful efforts method of accounting.
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.
Estimates of proved developed producing reserves are a major component of the calculation of depletion. 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.
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.
Exploration expense for 2023 significantly increased due to costs incurred to acquire seismic information related to our mineral and royalty interests. 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.
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.
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 Shelby Trough Development Update In Angelina County, Texas, 24 wells are currently producing under our development agreement with Aethon, and another 20 wells are being drilled or completed.
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.
Lease bonus and other income was slightly lower for the year ended December 31, 2023, as compared to the same period in 2022. Leasing activity in the Haynesville/Bossier and Wolfcamp plays made up the majority of lease bonus and other income in 2023 and 2022. Operating Expenses Lease operating expense.
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.
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 until February 26, 2024 at a redemption price of $21.41 per Series B cumulative convertible preferred unit, which is equal to 105% of par value.
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.
Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations and borrowings under our Credit Facility. Our primary uses of cash are for distributions to our unitholders, reducing outstanding borrowings under our Credit Facility as applicable, and for investing in our business.
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.
When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus. 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 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.
Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2023 were lower than the corresponding period in 2022 due to lower realized commodity prices partially offset by higher production volumes. The increase in oil and condensate production was primarily due to increased production volumes in the Permian Basin.
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.
The assets acquired consisted of $4.9 million of proved oil and natural gas properties, $15.6 million of unproved oil and natural gas properties, and $0.3 million of net working capital. See "Note 4 – Oil and Natural Gas Properties" to the consolidated financial statements included elsewhere in this Annual Report for additional information.
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.
Gain (loss) on commodity derivative instruments. Cash settlements we receive represent realized gains, while cash settlements we pay represent realized losses related to our commodity derivative instruments. In addition to cash settlements, we also recognize fair value changes on our commodity derivative instruments in each reporting period.
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.
The following table shows natural gas storage volumes by region at the end of each quarter presented: 2023 Region 1 Fourth Quarter Third Quarter Second Quarter First Quarter (Bcf) East 799 847 643 335 Midwest 968 991 705 421 Mountain 228 239 173 80 Pacific 280 278 216 73 South Central 1,201 1,090 1,141 921 Total 3,476 3,445 2,878 1,830 1 Source: EIA Natural Gas Exports The EIA expects exports of natural gas, both by pipeline and as LNG, will increase in 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 amount of the borrowing base is redetermined semi-annually, usually in October and April. In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027, increased the borrowing base to $550.0 million and elected to lower commitments under the Credit Facility to $375.0 million.
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.
Removed
Under a separate development agreement with Aethon in San Augustine County, Texas, 13 wells are currently producing, and another four wells are either drilling or awaiting completion operations. In December 2023, we received notice that Aethon was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas.
Added
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.
Removed
When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period. Aethon has not previously invoked the time-out provisions under the agreements.
Added
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.
Removed
The time-out provisions apply only to drilling obligations and associated development activity occurring after December 2023. Based on ongoing discussions with Aethon, we do not expect material changes for wells on which drilling operations had begun prior to the invocation of the time-out in December 2023.
Added
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.
Removed
We continue working closely with Aethon to finalize development plans going forward and assess the effect of the temporary suspension of drilling obligations and any potential longer-term impacts. Austin Chalk Update We own a large mineral position in the Brookeland Austin Chalk play in East Texas.
Added
Farmout Agreements In September and December 2024, two of our farmout agreements covering non-operated working interests in San Augustine County terminated. Consistent with our policy to minimize participation in working interests, we do not intend to step into the working interests associated with the terminated agreements.
Removed
We have entered into agreements with multiple operators to drill wells in the areas of the Austin Chalk in East Texas, where we have significant acreage positions.
Added
Unless we agree otherwise with Aethon, we believe that Aethon, as operator and the party who has proposed the existing wells, has absorbed and will continue to absorb any non-consented interests. 47 Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us.
Removed
The results of the test program in the Brookeland Field demonstrated that modern completion technology has the potential to improve production rates and increase reserves when compared to the vintage, unstimulated wells in the Austin Chalk formation.
Added
Oil prices rose in early 2024 due to heightened geopolitical risks, including attacks on vessels in the Red Sea and elevated tensions in the region, but declined later in the year due to market oversupply concerns.
Removed
To date, 29 wells with modern completions are now producing in the field. 48 Business Environment The information below is designed to give a broad overview of the oil and natural gas business environment as it affects us. Commodity Prices and Demand Oil and natural gas prices have been historically volatile based upon the dynamics of supply and demand.
Added
Natural gas prices decreased sharply in late 2023 and early 2024 due to surplus storage but increased in the second quarter of 2024 due to reduced drilling and production curtailments. This upward trend continued into the third and fourth quarters, driven by high energy demand from extreme temperatures and increased LNG exports.
Removed
Commodity prices during 2023 decreased from the corresponding prior period due to several factors, including reduced demand for natural gas and rising global oil inventories. The U.S. Energy Information Administration ("EIA") forecasts natural gas prices to be slightly higher in 2024 because of slowing growth in natural gas production and increasing U.S.
Added
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.
Removed
LNG exports, particularly following the addition of new export capacity expected toward the end of the year. The slowing growth reflects a drop in natural gas production associated with oil drilling in the Permian Basin.
Added
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.
Removed
However, the EIA expects upward price pressures will be limited by relatively flat consumption of natural gas in the electric power sector and persistently high inventories. For much of 2023, oil prices were relatively flat.
Added
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.
Removed
In September 2023, oil prices increased after Saudi Arabia extended its voluntary crude oil production cuts through the end of the year and U.S. commercial crude oil inventories fell to the lowest levels since early 2022.
Added
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.

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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 changeApplying this discount results in an approximate 2.0% reduction of proved reserve volumes as compared to the undiscounted December 31, 2023 SEC pricing scenario. 60 Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
Biggest changeApplying 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.
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, 2023, 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 less than $0.1 million for the year ended December 31, 2024, assuming that our indebtedness remained constant throughout the period.
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, 2023.
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.
As of December 31, 2023, we had seven 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.
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.
During the twelve months ended December 31, 2023, we had weighted average outstanding borrowings under our Credit Facility of $3.4 million, bearing interest at a weighted-average interest rate of 7.36%.
During 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%.

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