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What changed in Black Stone Minerals, L.P.'s 10-K — 2022 vs 2023

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Paragraph-level year-over-year comparison of Black Stone Minerals, L.P.'s 2022 and 2023 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 2023 report.

+190 added−203 removedSource: 10-K (2024-02-20) vs 10-K (2023-02-23)

Top changes in Black Stone Minerals, L.P.'s 2023 10-K

190 paragraphs added · 203 removed · 150 edited across 4 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

65 edited+10 added−4 removed239 unchanged
Biggest changeDespite 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.
Biggest changeThe 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.
Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with 39 their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible, or effective in all circumstances.
Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible, or effective in all circumstances.
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. General Risk Factors We have and will continue to incur increased costs as a result of being a publicly traded partnership.
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.
If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions to unitholders. 31 Acquisitions Any acquisitions of additional mineral and royalty interests will be subject to substantial risks.
If we are unable to fund our capital requirements, we may be unable to complete acquisitions, take advantage of business opportunities, or respond to competitive pressures, any of which could have a material adverse effect on our results of operation and cash distributions to unitholders. Acquisitions Any acquisitions of additional mineral and royalty interests will be subject to substantial risks.
Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. 28 The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage. The results of exploratory drilling in shale plays will be subject to risks associated with drilling and completion techniques and drilling results may not meet our expectations for reserves or production.
To the extent the rule imposes additional reporting obligations, we could face increased costs. Separately, the SEC has announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s climate disclosures are misleading or deficient.
To the extent the rule imposes additional reporting obligations, we could face increased costs. Separately, the SEC has announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s climate disclosures are misleading, deceptive or deficient.
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.
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.
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 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 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.
Non-U.S. common unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from 40 owning our common units. Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”).
Non-U.S. common unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our common units. Non-U.S. common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”).
Our Credit Facility restricts, and any future Credit Facility likely will restrict, our ability to: • incur indebtedness; • grant liens; • make certain acquisitions and investments; • enter into hedging arrangements; 30 • enter into transactions with our affiliates; • make distributions to our unitholders; or • enter into a merger, consolidation, or sale of assets.
Our Credit Facility restricts, and any future Credit Facility likely will restrict, our ability to: • incur indebtedness; • grant liens; • make certain acquisitions and investments; • enter into hedging arrangements; • enter into transactions with our affiliates; • make distributions to our unitholders; or • enter into a merger, consolidation, or sale of assets.
In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from this 41 disposition.
In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from this disposition.
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 35 units are outstanding. Please read Part II, Item 5.
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. Please read Part II, Item 5.
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.
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.
Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential 33 federal or state legislation governing hydraulic fracturing.
Legislative changes could cause operators to incur substantial compliance costs. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.
From 38 time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.
From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.
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 34 their investment and voting decisions.
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.
To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, executed farmout agreements, and the issuance of equity securities.
To date, we have financed capital 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.
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.
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.
For example, Section 404 requires us, among 42 other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.
For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.
Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management. 32 Laws and regulations governing exploration and production may also affect production levels.
Moreover, these laws and regulations have generally imposed increasingly strict requirements related to water use and disposal, air pollution control, and waste management. Laws and regulations governing exploration and production may also affect production levels.
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.
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
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. 27 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. 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.
Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our 37 liabilities to exceed the fair value of our assets.
Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.
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, 2022 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, 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.
"Business and properties — Environmental Matters — Hydraulic Fracturing" for a description of the laws and regulations that affect our operators and that may affect us.
"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.
Our estimates of proved reserves and related valuations as of December 31, 2022, 2021, and 2020 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, 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.
For the year ended December 31, 2022, 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, 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.
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; 25 • 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, including as a result of global pandemics similar to COVID-19; • 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 and the relationships between the United States and other countries, such as China and Russia; • the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities; • the price and availability of alternative fuels; and • overall domestic and global economic conditions.
Historically, oil and natural gas prices have been volatile and are subject to fluctuations in response to changes in supply and demand, market uncertainty, and a variety of additional factors that are beyond our control, including: • the domestic and foreign supply of and demand for oil and natural gas; • market expectations about future prices of oil and natural gas; • the level of global oil and natural gas exploration and production; • the cost of exploring for, developing, producing, and delivering oil and natural gas; • the price and quantity of foreign imports and exports of oil and natural gas; 23 • political and economic conditions in oil producing regions, including the Middle East, Africa, South America, 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.
The changes in the price of oil have been caused by many factors, including periods of increasing U.S. oil production 26 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 recent 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 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.
Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders. 29 Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations.
Sustained reductions in production by the operators on our properties may also adversely affect our results of operations and cash distributions to unitholders. 27 Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations.
The estimates of reserves as of December 31, 2022, 2021, and 2020 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, 2022, 2021, and 2020, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods.
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.
To the extent possible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return.
To the extent possible, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return.
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.
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 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.
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.
Approximately 56% of our 2022 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 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.
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, 2022, we had outstanding borrowings of $10.0 million 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, 2023, we had no outstanding borrowings and the aggregate maximum credit amounts of the lenders were $1.0 billion.
For a transfer of an interest in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and future prospective non-U.S. common unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
For a transfer of an interest in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker. Current and future prospective non-U.S. common unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.
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 44% of our 2022 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. Approximately 59% of our 2023 oil and natural gas revenues were derived from oil and condensate sales.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case 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 adjustments that were paid on such common unitholders' behalf.
If the IRS makes an audit adjustment to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case 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 adjustments that were paid on such common unitholders' behalf.
If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders would be substantially reduced.
If the IRS were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders would be substantially reduced.
In 2022, we generated 13% of our royalty revenues and 35% 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.
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.
The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S. natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, rising levels of U.S. natural gas exports, and recent fluctuations in demand as a result of the COVID-19 pandemic.
The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S. natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S. oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, and rising levels of U.S. natural gas exports.
If prices for oil are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties in addition to impairments taken during 2015, 2016, and 2020, and some of our undeveloped locations may no longer be economically viable.
If prices for oil are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties and some of our undeveloped locations may no longer be economically viable.
If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015, 2016, and 2020, and some of our undeveloped locations may no longer be economically viable.
If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties and some of our undeveloped locations may no longer be economically viable.
During the ten years prior to December 31, 2022, 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, 2022, the WTI spot market price of oil was $80.16.
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.
Securities and Exchange Commission (“SEC”) released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. A final rule is expected to be released early 2023, but we cannot predict what any such final rule may require.
In March 2022, the U.S. Securities and Exchange Commission (“SEC”) released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics. A final rule is expected to be released in 2024. We cannot predict what any such final rule may require.
Our borrowing base determined by the lenders under our Credit Facility in October 2022 was $550.0 million with outstanding commitments of $375.0 million and the next semi-annual redetermination is scheduled for April 2023. A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings.
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.
During the ten years prior to December 31, 2022, 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 31, 2022, the Henry Hub spot market price of natural gas was $3.52 per MMBtu.
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 $2.58 per MMBtu.
In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business. Our estimated reserves are based on many assumptions that may turn out to be inaccurate.
In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.
Year Ended December 31, 2022 During the Five Years Prior to 2022 As of December 31, High Low High 2 Low 3 2022 2021 2020 WTI spot crude oil ($/Bbl) 1 $ 123.64 $ 71.05 $ 123.64 $ 8.91 $ 80.16 $ 75.33 $ 48.35 Henry Hub spot natural gas ($/MMBtu) 1 9.85 3.46 23.86 1.33 3.52 3.82 2.36 1 Source: EIA 2 High prices for WTI and Henry Hub were in 2022 and 2021, respectively. 3 Low prices for WTI and Henry Hub were in 2020.
Year Ended December 31, 2023 During the Five Years Prior to 2023 As of December 31, High Low High 2 Low 3 2023 2022 2021 WTI spot crude oil ($/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.
As of December 31, 2022, we had 209,406,927 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
As of December 31, 2023, we had 209,991,223 common units and 14,711,219 Series B cumulative convertible preferred units outstanding.
For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our common units.
For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them.
While we are currently focused on organic growth of our existing assets and have farmed out most of our non-operated working interests, it is possible that we may need access to capital for those activities in the future.
While we are currently focused on organic growth of our existing assets and have farmed out most of our non-operated working interests, we expect to make opportunistic acquisitions to complement our existing acreage positions and may need access to capital for those activities in the future.
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.
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.
However, subject to certain exceptions, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our Series B cumulative convertible preferred units without Series B cumulative convertible preferred unitholder approval. 36 Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our Series B cumulative convertible preferred units.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests, including common units, without a vote of the unitholders other than, in certain instances, approval of holders of our Series B cumulative convertible preferred units.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes an audit adjustment to our income tax return, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us.
If the IRS makes an audit adjustment to our income tax return, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us.
These rules are not applicable for tax years beginning on or prior to December 31, 2017. Even if you, as a common unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
Even if you, as a common unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.
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.
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.
Our partnership agreement generally provides that any distributions are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7% per annum, subject to certain adjustments, and (ii) second, to the holders of common units.
Our partnership agreement generally provides that any distributions are paid each quarter as follows: (i) first, to the holders of Series B cumulative convertible preferred units equal to 7.0% of the face amount of the preferred units per annum through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter, and (ii) second, to the holders of common units.
However, we have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.
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.
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.
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.
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. In March 2022, the U.S.
“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.
If any of these risks are realized and production is not replaced by another operator in this area or another area, production may decrease, reducing cash generated from operations and cash available for distribution.
“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.
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.
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.
We may issue additional common units and other equity interests without common unitholder approval, which would dilute holders of common units.
We may issue additional common units and other equity interests without common unitholder approval, which would dilute holders of common units. However, subject to certain exceptions, our partnership agreement does not authorize us to issue units ranking senior to or at parity with our Series B cumulative convertible preferred units without Series B cumulative convertible preferred unitholder approval.
Removed
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.
Added
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.
Removed
“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.
Added
It is too early to know the outcome of this review and any impact the results of such review may have on LNG export growth but slowing LNG export growth could adversely affect the demand for our products. Our estimated reserves are based on many assumptions that may turn out to be inaccurate.
Removed
Risks to Unitholders under Our Partnership Agreement The Board may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to pay any distributions at all on our common units.
Added
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.
Removed
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.
Added
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. For more information, please read Part II, Item 7.
Added
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.
Added
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.
Added
Additionally, undeveloped acreage has greater risk of title defects than developed acreage.
Added
Further, while unitholders of publicly traded partnerships are, subject to certain limitations, generally entitled to a deduction equal to 20% of their allocable share of a publicly traded partnership’s “qualified business income” (as further discussed below), this deduction is scheduled to expire with respect to taxable years beginning after December 31, 2025.
Added
Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.
Added
Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them.Tax-exempt entities should consult a tax advisor before investing in our common units.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

8 edited+2 added−0 removed19 unchanged
Biggest changeAny 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 receive cumulative quarterly distributions in an amount equal to 7.0% of the face amount of the preferred units per annum (the “Distribution Rate”), provided that the Distribution Rate will be adjusted as follows: commencing on November 28, 2023 and readjusting every two years thereafter (each, a “Readjustment Date”), the rate will equal the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter.
Biggest changeThe rate set on each Readjustment Date is equal to the greater of (i) the Distribution Rate in effect immediately prior to the relevant Readjustment Date and (ii) the 10-year Treasury Rate as of such Readjustment Date plus 5.5% per annum; provided, however, that for any quarter in which quarterly distributions are accrued but unpaid, the then-Distribution Rate shall be increased by 2.0% per annum for such quarter.
Our cash distribution policy may be changed at any time by the Board and is subject to certain restrictions, including the following: • Our common unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our Series B cumulative convertible preferred unitholders. • Among other covenants, our Credit Facility requires we maintain a ratio of total debt to EBITDAX of 3.50:1.00 or less and a current ratio of 1.00:1.00 or greater.
Our cash distribution policy may be changed at any time by the Board and is subject to certain restrictions, including the following: • Our common unitholders have no contractual or other legal right to receive cash distributions from us on a quarterly or other basis, and if distributions are paid, common unitholders will receive distributions only to the extent the distribution amount exceeds distributions that are required to be paid to our Series B cumulative convertible preferred unitholders. • Among other covenants, our Credit Facility requires we maintain a ratio of total debt to EBITDAX of 3.5:1.0 or less and a current ratio of 1.0:1.0 or greater.
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 17, 2023, 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 16, 2024, 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 30, 2017.
The graph assumes that the value of the investment in our common units was $100.00 on December 31, 2018.
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 17, 2023, there were 209,683,640 common units outstanding held by 389 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 16, 2024, there were 210,313,477 common units outstanding held by 368 holders of record.
We have the option to redeem all or a portion (equal to or greater than $100 million) of the Series B cumulative convertible preferred units for a 90-day period beginning on November 28, 2023 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 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.
Cash Distribution Policy Our partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7% per annum, subject to certain adjustments; and • second , to the holders of common units.
Cash Distribution Policy Our partnership agreement generally provides that any distributions are paid each quarter in the following manner: • first , to the holders of the Series B cumulative convertible preferred units in an amount equal to 7.0% of the face amount of the preferred units per annum, through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter; and • second , to the holders of common units.
Cumulative return is computed assuming reinvestment of distributions. 44 Comparison of Cumulative Total Return Assumes Initial Investment of $100 As of December 31, 2017 2018 2019 2020 2021 2022 Black Stone Minerals, L.P. $ 100.00 $ 92.77 $ 83.15 $ 46.88 $ 77.15 $ 135.78 S&P 500 Index 100.00 95.62 125.72 148.85 191.58 156.88 S&P Oil & Gas E&P Index 100.00 71.90 65.11 41.73 69.51 100.82 The information in this Annual Report appearing under the heading “Common Unit Performance Graph” is being furnished pursuant to Item 201(e) of Regulation S-K and shall not be deemed to be “soliciting material” or to be “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act.
Cumulative return is computed assuming reinvestment of distributions. 44 Comparison of Cumulative Total Return Assumes Initial Investment of $100 As of December 31, 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.
Added
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”).
Added
On November 28, 2023, the Distribution Rate was adjusted to 9.8% and will be readjusting every two years thereafter (each, a “Readjustment Date”).

Item 7. Management's Discussion & Analysis

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

72 edited+28 added−49 removed47 unchanged
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, 2022 2021 (in thousands) Net income (loss) $ 476,480 $ 181,987 Adjustments to reconcile to Adjusted EBITDA: Depreciation, depletion, and amortization 47,804 61,019 Interest expense 6,286 5,638 Income tax expense (benefit) 58 (135) Accretion of asset retirement obligations 861 1,073 Equity-based compensation 17,388 12,218 Unrealized (gain) loss on commodity derivative instruments (82,486) 33,528 (Gain) loss on sale of assets, net (17) (2,850) Adjusted EBITDA 466,374 292,478 Adjustments to reconcile to Distributable cash flow: Change in deferred revenue (30) (18) Cash interest expense (4,282) (4,059) Preferred unit distributions (21,000) (21,000) Distributable cash flow $ 441,062 $ 267,401 53 Results of Operations Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 The following table shows our production, revenue, and operating expenses for the periods presented: Year Ended December 31, 2022 2021 Variance (dollars in thousands, except for realized prices) Production: Oil and condensate (MBbls) 3,591 3,646 (55) (1.5) % Natural gas (MMcf) 1 59,778 61,445 (1,667) (2.7) % Equivalents (MBoe) 13,554 13,887 (333) (2.4) % Equivalents/day (MBoe) 37.1 38.0 (0.9) (2.4) % Realized prices, without derivatives: Oil and condensate ($/Bbl) $ 93.65 $ 64.67 $ 28.98 44.8 % Natural gas ($/Mcf) 1 7.28 4.16 3.12 75.0 % Equivalents ($/Boe) $ 56.90 $ 35.39 $ 21.51 60.8 % Revenue: Oil and condensate sales $ 336,287 $ 235,771 $ 100,516 42.6 % Natural gas and natural gas liquids sales 1 434,945 255,671 179,274 70.1 % Lease bonus and other income 13,052 14,292 (1,240) (8.7) % Revenue from contracts with customers 784,284 505,734 278,550 55.1 % Gain (loss) on commodity derivative instruments (120,680) (146,474) 25,794 (17.6) % Total revenue $ 663,604 $ 359,260 $ 304,344 84.7 % Operating expenses: Lease operating expense $ 12,380 $ 13,056 $ (676) (5.2) % Production costs and ad valorem taxes 66,233 49,809 16,424 33.0 % Exploration expense 193 1,082 (889) (82.2) % Depreciation, depletion, and amortization 47,804 61,019 (13,215) (21.7) % General and administrative 53,652 48,746 4,906 10.1 % Other expense: Interest expense 6,286 5,638 648 11.5 % 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. 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.
In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer 49 months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.
In order to maintain sufficient storage levels for increased seasonal demand, a portion of natural gas production during the summer months must be used for storage injection. The portion of production used for storage varies from year to year depending on the demand from the previous winter and the demand for electricity used for cooling during the summer months.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation 58 and judgment.
Reservoir engineering is a subjective process of estimating underground accumulations of oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved oil and natural gas reserves. The accuracy of any reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.
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 2022 and 2021.
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.
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, 2022, 2021, and 2020.
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.
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, 2022 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, 2023 are detailed in Note 5 – Commodity Derivative Financial Instruments to our consolidated financial statements included elsewhere in this Annual Report.
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, 2022 and 2021, 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. 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.
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: 2022 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: 2023 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, 2022 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, 2023 reserve report.
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 2022 increased as compared to 2021.
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.
We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, proceeds from any future issuances of equity and debt, and proceeds from asset sales.
We intend to finance any future acquisitions with cash generated from operations, borrowings from our Credit Facility, and proceeds from any future issuances of equity and debt.
Lease operating expense decreased in 2022 as compared to 2021, primarily due to a decrease 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 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.
For the discussion of changes from 2020 to 2021 and other financial information related to 2020, refer to “Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations" in our 2021 Annual Report on Form 10-K, which was filed with the SEC on February 22, 2022.
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.
DD&A expense related to our producing oil and natural gas properties was $47.2 million, $60.4 million, and $81.3 million for the years ended December 31, 2022, 2021, and 2020, 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 $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.
Applying this discount results in an approximate 0.7% reduction of estimated proved reserve volumes as compared to the undiscounted pricing scenario used in our December 31, 2022 reserve report prepared by NSAI.
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.
As of December 31, 2022, 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 over 68,000 producing wells.
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.
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, 2022, we had hedged 81% of our available oil and condensate hedge volumes and 68% of our available natural gas hedge volumes for 2023.
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.
Our mineral and royalty interest oil and condensate volumes accounted for 93% of total oil and condensate volumes for each of the years ended December 31, 2022 and 2021. Natural gas and natural gas liquids sales.
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.
The increase was primarily due to higher distributions paid to common unitholders as well as higher net repayments under our Credit Facility in 2022 compared with 2021. 56 Development Capital Expenditures In the first quarter of each calendar year, we establish a capital budget and then monitor it throughout the year.
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.
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. Lease bonus and other income We also earn revenue from lease bonuses and delay rentals.
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.
Oil and Natural Gas Properties We follow the successful efforts method of accounting for oil and natural gas operations. 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.
Net cash used in investing activities for 2022 decreased as compared to 2021. The change was primarily due to minimal acquisition activity and lower net oil and gas capital expenditures in 2022 compared to the same period in 2021. Financing Activities . Cash flows used in financing activities for 2022 increased as compared to 2021.
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.
Given the dynamic nature of these events, we cannot reasonably estimate the period of time that 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 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.
Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date. Acquisitions that consist of all or substantially all unproved oil and natural gas properties are generally considered asset acquisitions and are recorded at cost.
Acquisitions of proved oil and natural gas properties and working interests are generally considered business combinations and are recorded at their estimated fair value as of the acquisition date.
Prior-period performance obligations We record oil and natural gas revenue in the month production is delivered to the purchaser. As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered.
As a non-operator, we have limited visibility into the timing of when new wells start producing and production statements may not be received for 30 to 90 days or more after the date production is delivered.
During 2022, we recognized $203.2 million of realized losses and $82.5 million of unrealized gains from our commodity derivatives, compared to $112.9 million of realized losses and $33.5 million of unrealized losses in 2021.
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.
The EIA forecasts that inventories will conclude the withdrawal season, which is the end of March 2023, at 1.8 Tcf, or 16% higher than the five-year average. The EIA expects inventories will rise to 3.8 Tcf at the end of October 2023, which would be 5% higher than the five-year average.
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.
We have provided expanded discussion of our more significant accounting estimates below. Please read the notes to the consolidated financial statements included elsewhere in this Annual Report for additional information regarding our accounting policies.
We have provided expanded discussion of our more significant accounting estimates below. See "Note 2 – Summary of Significant Accounting Policies" within the consolidated financial statements included elsewhere in this Annual Report for additional information.
We recognized $51.0 million of impairment of proved oil and natural gas properties for the year ended December 31, 2020. 59 Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value.
Unproved properties are also assessed for impairment periodically on a depletable unit basis when facts and circumstances indicate that the carrying value may not be recoverable, at which point an impairment loss is recognized to the extent the carrying value exceeds the estimated recoverable value.
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.
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.
The reduction in cost basis is primarily due to continued depreciation, depletion, and amortization. General and administrative. General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services.
General and administrative expenses are costs not directly associated with the production of oil and natural gas and include the cost of employee salaries and related benefits, office expenses, and fees for professional services.
In October 2022, we revised and amended the Credit Facility to extend the maturity date from November 1, 2024 to October 31, 2027. Concurrent with the Credit Facility amendment, the borrowing base under the Credit Facility was increased to $550.0 million and we elected to lower commitments under the Credit Facility from $400.0 million to $375.0 million.
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 $375.0 million.
Revenue Total revenue for the year ended December 31, 2022 increased compared to the year ended December 31, 2021. The increase in total revenue from the corresponding period is primarily due to higher realized commodity prices partially offset by lower production volumes.
Revenue Total revenue for the year ended December 31, 2023 decreased compared to the year ended December 31, 2022. The decrease in total revenue from the corresponding period is primarily due to lower realized commodity prices partially offset by an increase in production volumes and a gain on commodity derivative instruments in 2023 compared to a loss in 2022.
Revenues from Contracts with Customers Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified.
Revenues from Contracts with Customers Accounting Standards Codification ("ASC") 606, Revenue from Contracts with Customers , requires us to identify the distinct promised goods and services within a contract which represent separate performance obligations and determine the transaction price to allocate to the performance obligations identified. 59 Oil and natural gas sales Sales of oil and natural gas are recognized at the point control of the product is transferred to the customer and collectability of the sales price is reasonably assured.
The following table reflects commodity prices at the end of each quarter presented: 2022 Benchmark Prices Fourth Quarter Third Quarter Second Quarter First Quarter WTI spot crude oil ($/Bbl) 1 $ 80.16 $ 79.91 $ 107.76 $ 100.53 Henry Hub spot natural gas ($/MMBtu) 1 $ 3.52 $ 6.40 $ 6.54 $ 5.46 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: 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.
Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped.
DD&A of producing oil and natural gas properties is recorded based on the units-of-production method. Capitalized development costs are amortized on the basis of proved developed reserves while leasehold acquisition costs and the costs to acquire proved properties are amortized on the basis of all proved reserves, both developed and undeveloped.
TLW holds non-operating working interests and overriding royalty interests primarily located in Oklahoma and Texas. Acquisitions In the second quarter of 2021, we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units of the Partnership.
During 2021 we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million. The purchase price consisted of $10.0 million in cash and $10.8 million in common units.
The unrealized gains on our commodity contracts in 2022 and unrealized losses in 2021 were both primarily driven by changes in the forward commodity price curves for oil and natural gas. Lease bonus and other income . When we lease our mineral interests, we generally receive an upfront cash payment, or a lease bonus.
The unrealized gains on our commodity contracts in 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 costs of unproved leaseholds and non-producing mineral interests are capitalized as unproved properties pending the results of exploration and leasing efforts. As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist.
As unproved properties are determined to be productive, the related costs are transferred to proved oil and natural gas properties. The costs related to exploratory wells are capitalized pending determination of whether proved commercial reserves exist. If proved commercial reserves are not discovered, such drilling costs are expensed.
A decrease in the loss on commodity derivative instruments in 2022 further contributed to the overall increase in revenue. Oil and condensate sales. Oil and condensate sales for the year ended December 31, 2022 were higher than the corresponding period in 2021 due to higher realized commodity prices partially offset by lower production volumes.
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.
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.
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.
We expect additional drilling by multiple operators over this area in the future. 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.
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.
A significant decline in oil or natural gas prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties are impaired. As future commodity prices cannot be predicted accurately, actual results could differ significantly from estimates.
The volatility of commodity prices results in increased uncertainty inherent in such estimates and assumptions. A significant decline in oil or natural gas prices could result in a reduction in our fair value estimates and cause us to perform analyses to determine if our oil and natural gas properties are impaired.
As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm.
As a result, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered. Our reserve estimates are determined by an independent petroleum engineering firm. We evaluate estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment.
Natural gas and NGL sales increased for the year ended December 31, 2022 as compared to the year ended December 31, 2021 due to higher realized commodity prices offset by lower production volumes. The decrease in natural gas and NGL production was driven by decreases in working interest production volumes, primarily within the Shelby Trough play.
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, 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.
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.
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. 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.
Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing. Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred.
In some circumstances, it may be uncertain whether proved commercial reserves have been discovered when drilling has been completed. Such exploratory well drilling costs may continue to be capitalized if the reserve quantity is sufficient to justify completion as a producing well and sufficient progress in assessing the reserves and the economic and operating viability of the project is ongoing.
Contractual Obligations The following table summarizes our minimum payments as of December 31, 2022 (in thousands): Payments due by period Total Less Than 1 Year 1-3 Years 3-5 Years More Than 5 Years Credit facility $ 10,000 $ — $ — $ 10,000 $ — Operating lease obligations 3,726 818 2,399 509 — Purchase commitments 537 430 107 — — Total $ 14,263 $ 1,248 $ 2,506 $ 10,509 $ — 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.
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.
As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A. DD&A of producing oil and natural gas properties is recorded based on the units-of-production method.
The basis for grouping is a reasonable aggregation of properties with a common geographic location, which we also refer to as a depletable unit. As exploration and development work progresses and the reserves associated with our oil and natural gas properties become proved, capitalized costs attributed to the properties are charged as an operating expense through DD&A.
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.
Oil is priced on the delivery date based upon prevailing prices published by purchasers with certain adjustments related to oil quality and physical location.
Rotary Rig Count 1 Fourth Quarter Third Quarter Second Quarter First Quarter Oil 621 604 594 531 Natural gas 156 159 157 137 Other 2 2 2 2 Total 779 765 753 670 1 Source: Baker Hughes Incorporated 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 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.
The increase was primarily due an increase in oil and condensate sales revenue and natural gas and NGL sales revenue due to higher realized commodity prices in 2022 compared to the same period of 2021. The overall increase was partially offset by an increase in net cash paid on settlements of commodity derivative instruments. Investing Activities .
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.
Cash Flows Year Ended December 31, 2022 Compared to Year Ended December 31, 2021 The following table shows our cash flows for the periods presented: Year Ended December 31, 2022 2021 Change (in thousands) Cash flows provided by operating activities $ 424,983 $ 256,880 $ 168,103 Cash flows provided by (used in) investing activities (1,215) (14,317) 13,102 Cash flows provided by (used in) financing activities (428,337) (235,483) (192,854) Operating Activities .
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 .
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 for 2022 was minimal. Exploration expense for 2021 primarily related to a dry hole drilled in the first quarter of 2021. Depreciation, depletion, and amortization.
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.
The purchase price consisted of $10.0 million in cash and $10.8 million in common units. 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.
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.
Leasing activity in the Wolfcamp and Haynesville/Bossier plays made up the majority of lease bonus and other income in 2022.
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.
The timing, size, and nature of acquisitions are unpredictable. Our 2023 capital expenditure budget associated with our non-operated working interests is expected to be approximately $6.9 million, net of farmout reimbursements.
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.
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, 2022 as compared to 2021, primarily due to lower production volumes and a reduction in cost basis.
Estimates of proved developed producing reserves are a major component of the calculation of depletion. We adjust our depletion rates semi-annually based upon the mid-year and year-end reserve reports, except when circumstances indicate that there has been a significant change in reserves or costs.
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. 60 Lease bonus and other income Given that we do not recognize lease bonus or other income until a lease agreement has been executed, at which point its performance obligation has been satisfied, and payment is received, we do not record revenue for unsatisfied or partially unsatisfied performance obligations as of the end of the reporting period.
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.
We spent approximately $0.6 million and $4.2 million associated with our non-operated working interests, net of farmout reimbursements during 2022 and 2021, respectively. Acquisitions We had no material acquisition activity during 2022. During 2021 we closed an acquisition of mineral and royalty acreage in the northern Midland Basin for total consideration of $20.8 million.
We spent approximately $4.8 million and $0.6 million associated with our non-operated working interests, net of farmout reimbursements during 2023 and 2022, respectively. Acquisitions During the year ended December 31, 2023, we acquired mineral and royalty interests for cash consideration of $14.6 million, including capitalized direct transaction costs.
Shelby Trough Update In Angelina County, Texas, ten wells are currently producing under our development agreement with Aethon, and another ten wells are being drilled or completed. Under a separate development agreement with Aethon in San Augustine Texas, four wells are currently producing and another six wells are either drilling or awaiting completion operations.
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.
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.
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.
The increase in equity-based compensation was due to higher costs recognized for performance-based incentive awards resulting from upward movements in our common unit price during 2022 compared to 2021. The overall increase was partially offset by a $2.1 million recovery in allowance against an outstanding long-term receivable. Other Expense Interest expense.
The overall decrease was partially offset by increases in consulting costs of $2.6 million related to internal projects and a non-recurring $2.1 million recovery in allowance against an outstanding long-term receivable in 2022. Other Expense Interest expense.
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 lower for the year ended December 31, 2022, as compared to the same period in 2021.
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.
For the year ended December 31, 2022, general and administrative expenses increased compared to 2021, primarily due to a $1.9 million increase in cash compensation and a $4.8 million increase in equity-based compensation. The increase in 55 cash compensation was driven by projected outperformance relative to performance targets under our short-term cash incentive plan.
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.
For the year ended December 31, 2022, interest expense increased compared to 2021, primarily due to higher interest rates under our Credit Facility. Liquidity and Capital Resources Overview Our primary sources of liquidity are cash generated from operations, borrowings under our Credit Facility, and proceeds from the issuance of equity and debt.
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.
Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification. The basis for grouping is a reasonable aggregation of properties with a common geographic location, which we also refer to as a depletable unit.
Other exploratory costs, including annual delay rentals and geological and geophysical costs, are expensed when incurred. Oil and natural gas properties are grouped in accordance with the Extractive Industries – Oil and Gas Topic of the Financial Accounting Standards Board Accounting Standards Codification.
There are no cure periods for events of default due to non-payment of principal and breaches of negative and financial covenants, but non-payment of interest and breaches of certain affirmative covenants are subject to customary cure periods. As of December 31, 2022, 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, 2023, we were in compliance with all debt covenants.
The EIA forecasts average exports of 11.8 Bcf per day for 2023. 50 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance.
It is too early to know the outcome of this review and any impact the results of such review may have on LNG export growth. 50 How We Evaluate Our Operations We use a variety of operational and financial measures to assess our performance.
Mineral and royalty interest production accounted for 92% and 84% of our natural gas volumes for the years ended December 31, 2022 and 2021, 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.
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.
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 TLW Divestiture In the third quarter of 2021, we closed on the divestiture of our wholly owned subsidiary, TLW Investments, L.L.C. ("TLW"), effective September 1, 2021 for total proceeds of $0.2 million.
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.
Removed
Overview We are one of the largest owners and managers of oil and natural gas mineral interests in the United States. Our principal business is maximizing the value of our existing portfolio of mineral and royalty assets through active management and expanding our asset base through acquisitions of additional mineral and royalty interests.
Added
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.
Removed
We maximize value through marketing our mineral assets for lease, creatively structuring the terms on those leases to encourage and accelerate drilling activity, and selectively participating alongside our lessees on a working interest basis.
Added
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.
Removed
We believe our large, diversified asset base and long-lived, non-cost-bearing mineral and royalty interests provide for stable production and reserves over time, allowing the majority of generated cash flow to be distributed to unitholders.
Added
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.
Removed
The cash consideration was funded with borrowings under the Credit Facility and funds from operating activities. 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.
Added
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.

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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 changeAs of December 31, 2022, we had $10.0 million of outstanding borrowings under our Credit Facility, bearing interest at a weighted-average interest rate of 6.92%.
Biggest changeDuring 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%.
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, 2022.
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.
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 $0.1 million for the year ended December 31, 2022, 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, 2023, assuming that our indebtedness remained constant throughout the period.
As of December 31, 2022, we had seven counterparties, all of which are rated Baa1 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, 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.
Applying this discount results in an approximate 0.7% reduction of proved reserve volumes as compared to the undiscounted December 31, 2022 SEC pricing scenario. Counterparty and Customer Credit Risk Our derivative contracts expose us to credit risk in the event of nonperformance by counterparties.
Applying this discount results in an approximate 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.

Other BSM 10-K year-over-year comparisons