TXO Partners LP

Previous wording

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Changes in oil, natural gas and NGL prices have a significant impact on the amount of oil, natural gas and NGL that we can produce economically, the value of our reserves and on our cash flows. Historically, oil, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. For example, during the period from January 1, 2021 through December 31, 2023, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $47.62 per Bbl and $1.99 per MMBtu, respectively. Oil prices steadily increased through 2021 due to continued recovery in demand before increasing drastically in the first half of 2022 due to further demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 and the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in the last month of 2023 and first month of 2024. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

Current wording

These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements accurately. Changes in oil, natural gas and NGL prices have a significant impact on the amount of oil, natural gas and NGL that we can produce economically, the value of our reserves and on our cash flows. Historically, oil, natural gas and NGL prices and markets have been volatile, and those prices and markets are likely to continue to be volatile in the future. For example, during the period from January 1, 2022 through December 31, 2024, prices for crude oil and natural gas reached a high of $123.70 per Bbl and $9.68 per MMBtu, respectively, and a low of $65.75 per Bbl and $1.58 per MMBtu, respectively. Oil prices increased drastically in the first half of 2022 due to demand, domestic supply reductions, OPEC control measures and market disruptions resulting from the Russia-Ukraine war and sanctions on Russia. Oil prices moderated over the second half of 2022 and the first half of 2023 before initially increasing in the second half of 2023 as a result of expected supply constraints and hostilities in the Middle East. Since these concerns did not materialize, oil prices declined in December 2023 but continuing hostilities and higher global consumption pushed prices higher in the first half of 2024. However, increased supply led to lower prices in the second half of 2024. Any substantial decline in the price of oil and natural gas will likely have a material adverse effect on our financial condition, results of operations and cash available for distribution.

Previous wording

Prior to 2021, our historical impairment of proved properties included $311.5 million of proved property impairments from 2014 through 2020. Due to the improvement in commodity pricing environment and industry conditions, we did not record any impairments in 2022 or 2021. However, with the decline of commodity prices late in 2023, increased costs and a change in our policy of recording proved undeveloped reserves, werecorded an impairment of long-lived assets of $223.4 million for the year ended December 31, 2023. The impairment is related toour assets in the Texas Permian Basin that are within our Cross Timbers joint venture. In the future, if commodity prices fall below certain levels, our production, proved reserves and cash flows will be adversely impacted and we may be required to record additional impairments, which could be material. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which may be determined at the discretion of our lenders. See “—Any significant reduction in the borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

Current wording

Prior to 2022, our historical impairment of proved properties included $311.5 million of proved property impairments from 2014 through 2021. Due to the improvement in commodity pricing environment and industry conditions, we did not record any impairments in 2022 or 2024. However, with the decline of commodity prices late in 2023, increased costs and a change in our approach to recording proved undeveloped reserves, werecorded an impairment of long-lived assets of$223.4 million for the year ended December 31, 2023. The impairment was related toour assets in the Texas Permian Basin that are within our Cross Timbers joint venture. In the future, if commodity prices fall below certain levels, our production, proved reserves and cash flows will be adversely impacted and we may be required to record additional impairments, which could be material. Lower oil and natural gas prices may also result in a reduction in the borrowing base under our Credit Facility, which may be determined at the discretion of our lenders. See “—Any significant reduction in the borrowing base under our Credit Facility as a result of periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.”

Previous wording

Currently, our producing properties are concentrated in the Permian and San Juan Basins, making us vulnerable to risks associated with operating in a limited number of geographic areas.

Current wording

Currently, our producing properties are concentrated in the Permian, San Juan and Williston Basins, making us vulnerable to risks associated with operating in a limited number of geographic areas.

Previous wording

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. For example, during 2022 and the first half of 2023, the Federal Reserve raised the target range for the federal funds rate by 525 basis points to a range of 5.25% to 5.50% as of August, 2023. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

Current wording

Our business could be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in our credit rating. For example, during 2022 and the first half of 2023, the Federal Reserve raised the target range for the federal funds rate by 525 basis points to a range of 5.25% to 5.50% as of August 2023. While the Federal Reserve lowered the federal funds rate during 2024 to a range of 4.25% to 4.50%, our interest rate on our Credit Facility remains elevated at 8.3% as of December 31, 2024. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows available and place us at a competitive disadvantage. Continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our activities. A significant reduction in the availability of credit could materially and adversely affect our ability to achieve our business strategy and cash flows.

Previous wording

We conduct certain of our operations through Cross Timbers, a joint venture owned 50% by us and 50% by the XTO Entities. For the year ended December 31, 2023, our interest in Cross Timbers represented approximately 27% of our revenues excluding the effects of our commodity derivative contracts and approximately 25% of our proved reserves.

Current wording

We conduct certain of our operations through Cross Timbers, a joint venture owned 50% by us and 50% by the XTO Entities. For the year ended December 31, 2024, our interest in Cross Timbers represented approximately 24% of our revenues excluding the effects of our commodity derivative contracts and approximately 24% of our proved reserves.

Previous wording

The majority of the scientific community has concluded that climate change is expected to result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wild fires, in each case which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment.

Current wording

The majority of the scientific community has concluded that climate change is expected to result in more frequent and/or more extreme weather events, changes in temperature and precipitation patterns, changes to ground and surface water availability, and other related phenomena, which could affect some, or all, of our operations. Our development, optimization and exploitation activities and equipment could be adversely affected by extreme weather conditions, such as hurricanes, thunderstorms, tornadoes and snow or ice storms, or other climate-related events such as wildfires, in each case which may cause a loss of production from temporary cessation of activity or lost or damaged facilities and equipment.

Previous wording

Climate change is also expected to result in various chronic impacts, such as changes to water levels and to ambient temperature and precipitation patterns. Such changes may also adversely impact our operations, including through the long-term reduction in the availability of water for hydraulic fracturing, changes to operational practices to respond to increased heat levels, or otherwise.

Current wording

Climate change could result in various chronic impacts, such as changes to water levels and to ambient temperature and precipitation patterns. Such changes may also adversely impact our operations, including through the long-term reduction in the availability of water for hydraulic fracturing, changes to operational practices to respond to increased heat levels, or otherwise.

Previous wording

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive since 2022, increasing the cost of salaries, wages, supplies, material, freight, and energy. We expect relatively higher inflation to continue in 2024 resulting in higher costs. Though we incorporated inflationary factors into our 2024 business plan, inflation may outpace those assumptions. We continue to undertake actions and implement plans to strengthen our supply chain to address these pressures and protect the requisite access to commodities and services. Nevertheless, we expect for the foreseeable future to experience supply chain constraints and inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs for the year ended December 31, 2023 compared to the year ended December 31, 2022. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. If we are unable to recover higher costs through higher commodity prices, our current revenue stream could be adversely impacted and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Current wording

Concerns over global economic conditions, energy costs, supply chain disruptions, increased demand, labor shortages associated with a fully employed U.S. labor force, geopolitical issues, inflation, the availability and cost of credit and the United States financial market and other factors have contributed to increased economic uncertainty and diminished expectations for the global economy. During the year ended December 31, 2022, the U.S. economy experienced the highest rate of inflation in the past 40 years. Rising inflation has been pervasive since 2022, increasing the cost of salaries, wages, supplies, material, freight, and energy. While we have seen inflation moderate in 2024, inflation continues to run higher than the Federal Reserve target, resulting in higher costs. Though we incorporated inflationary factors into our 2025 business plan, inflation may outpace those assumptions. We continue to undertake actions and implement plans to address these pressures and protect the requisite access to commodities and services, however, these mitigation efforts may not succeed or be insufficient. Nevertheless, we expect for the foreseeable future to experience inflationary pressure on our cost structure. Principally, commodity costs for steel and chemicals required for drilling, higher transportation and fuel costs and wage increases have increased our operating costs. We do not expect these cost increases to reverse in the short term. Typically, as prices for oil and natural gas increase, so do associated costs. Conversely, in a period of declining prices, associated cost declines are likely to lag and may not adjust downward in proportion to prices. If we are unable to recover higher costs through higher commodity prices, our current revenue stream could be adversely impacted and result in reduced margins and production delays and, as a result, our business, financial condition, results of operations and cash flows could be materially and adversely affected.

Previous wording

Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil, NGL and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities. While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. For example, revenues increased $134.3 million, or 55%, from $246.4 million for the year ended December 31, 2022 to $380.7 million for the year ended December 31, 2023. The increase was primarily attributable to net gains on our hedging activity of $226.4 million, of which $219.5 million were unrealized gains and $6.9 million were related to lower realized losses. Additionally, revenue increased $6.3 million in spite of a decrease in production of 69 MBoe primarily as a result of the acquisition of additional interest in the Permian Basin being offset by natural declines in San Juan Basin. These increases were partially offset by a decrease in the average selling price, excluding the effects of derivatives, on oil of 19%, resulting in a decrease in revenue of $39.2 million, on NGLs of 36%, resulting in a decrease in revenue of $17.3 million and on gas of 21%, resulting in a decrease in revenue of $42.0 million.

Current wording

Changes in the fair value of commodity price derivatives are recognized currently in earnings. Realized and unrealized gains and losses on commodity derivatives are recognized in oil, NGL and natural gas revenues. Settlements of derivatives are included in cash flows from operating activities. While our price risk management activities decrease the volatility of cash flows, they may obscure our reported financial condition. As required under GAAP, we record derivative financial instruments at their fair value, representing projected gains and losses to be realized upon settlement of these contracts in subsequent periods when related production occurs. These gains and losses are generally offset by increases and decreases in the market value of our proved reserves, which are not reflected in the financial statements. For example, revenues decreased $97.9 million, or 26%, from $380.7 million for the year ended December 31, 2023 to $282.8 million for the year ended December 31, 2024. The decrease was primarily attributable to a decrease in the average selling price, excluding the effects of derivatives, on oil of 4%, resulted in a decrease in revenue of $7.2 million and on gas of 60%, resulted in a decrease in revenue of $89.5 million. Additionally, net losses on our hedging activity of $25.7 million, of which $113.6 million were related to increased unrealized losses partially offset by $87.9 million related to lower realized losses. These decreases were partially offset by an increase in production of 162 MBoe which resulted in increased revenue of $22.4 million primarily as a result of the acquisition of producing assets in the Williston Basin being offset by natural declines in San Juan Basin and an increase in the average selling price, excluding the effects of derivatives, on NGLs of 8%, resulting in an increase in revenue of $2.2 million.

Previous wording

The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Current wording

The present value of future net cash flow from our proved reserves, or standardized measure, may not represent the current market value of our estimated proved oil, natural gas liquids and natural gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average oil and natural gas index prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties.

Previous wording

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. For example, our estimated proved reserves as of December 31, 2023 were calculated under SEC rules using the unweighted arithmetic average first day of the month prices for the prior 12 months of $2.64/MMBtu for natural gas and $78.22/Bbl for oil at December 31, 2023, which, for certain periods during this period, were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Current wording

Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. For example, our estimated proved reserves as of December 31, 2024 were calculated under SEC rules using the unweighted arithmetic average first day of the month prices for the prior 12 months of $2.13/MMBtu for natural gas and $75.48/Bbl for oil at December 31, 2024, which, for certain periods during this period, were substantially different from the available spot prices. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with Accounting Standards Codification 932, “Extractive Activities—Oil and Gas,” may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.

Previous wording

For the year ended December 31, 2023, Chevron USA and CIMA Energy together accounted for more than 42% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2022, Chevron USA and Phillips 66 Company together accounted for more than 35% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties—Operations—Marketing and Customers.”

Current wording

For the year ended December 31, 2024, Chevron USA and Gunvor USA together accounted for almost 46% of our total revenues, excluding the impact of our commodity derivatives. For the year ended December 31, 2023, Chevron USA and CIMA Energy together accounted for more than 42% of our total revenues, excluding the impact of our commodity derivatives. No other purchaser accounted for more than 10% of our revenue during such periods. We do not have long-term contracts with our customers; rather, we sell the substantial majority of our production under arm’s length contracts with terms of 12 months or less, including on a month-to-month basis, to a relatively small number of customers. The loss of any one of these purchasers, the inability or failure of our significant purchasers to meet their obligations to us or their insolvency or liquidation could materially adversely affect our financial condition, results of operations and ability to make distributions to our unitholders. We cannot assure you that any of our customers will continue to do business with us or that we will continue to have ready access to suitable markets for our future production. See “Business and Properties—Operations—Marketing and Customers.”

Previous wording

Our Credit Facility limits the amount we can borrow up to a borrowing base amount. The administrative agent under our Credit Facility determines our borrowing base based on the value of our oil and natural gas properties. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. As of October 25, 2023, the last date of redetermination, our borrowing base was $165 million. Such amount will be redetermined semi-annually on or before each March 15 and September 1 and will depend on the volumes of our proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Credit Facility, including our business, financial condition and debt obligations, the types of reserves, the value and effect of hedge contracts then in effect and the effect of gas imbalances. In addition, our lenders will have flexibility to reduce our borrowing base due to subjective factors.

Current wording

Our Credit Facility limits the amount we can borrow up to a borrowing base amount. The administrative agent under our Credit Facility determines our borrowing base based on the value of our oil and natural gas properties. The borrowing base is subject to further adjustments for asset dispositions, material title deficiencies, certain terminations of hedge agreements and issuances of permitted additional indebtedness. As of August 30, 2024, the last date of redetermination, our borrowing base was $275 million. Such amount will be redetermined semi-annually on or before each March 15 and September 1 and will depend on the volumes of our proved oil and natural gas reserves and estimated cash flows from these reserves and other information deemed relevant by the administrative agent under the Credit Facility, including our business, financial condition and debt obligations, the types of reserves, the value and effect of hedge contracts then in effect and the effect of gas imbalances. In addition, our lenders will have flexibility to reduce our borrowing base due to subjective factors.

Previous wording

We are required to record a liability for the discounted present value of our estimated asset retirement obligations to plug and abandon inactive wells and related assets and non-producing oil and gas properties in which we have a working interest. Such asset retirement obligations may include complete structural removal and/or restoration of the land. At December 31, 2023, we had accrued asset retirement obligations of $154.0 million. Although management has used its best efforts to determine future asset retirement obligations, assumptions and estimates can be influenced by many factors beyond management’s control, including, but not limited to, changes in regulatory requirements, which may be more restrictive in the future, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes and lightning storms, which may cause structural or other damage to oil and natural gas assets and properties. Accordingly, our estimate of future asset retirement obligations could differ materially from actual costs that may be incurred.

Current wording

We are required to record a liability for the discounted present value of our estimated asset retirement obligations to plug and abandon inactive wells and related assets and non-producing oil and gas properties in which we have a working interest. Such asset retirement obligations may include complete structural removal and/or restoration of the land. At December 31, 2024, we had accrued asset retirement obligations of $190.9 million. Although management has used its best efforts to determine future asset retirement obligations, assumptions and estimates can be influenced by many factors beyond management’s control, including, but not limited to, changes in regulatory requirements, which may be more restrictive in the future, changes in costs for abandonment related services and technologies, which could increase or decrease based on supply and demand, and/or extreme weather conditions, such as hurricanes and lightning storms, which may cause structural or other damage to oil and natural gas assets and properties. Accordingly, our estimate of future asset retirement obligations could differ materially from actual costs that may be incurred.

Previous wording

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. Governmental and other entities in various states, such as California and New York, have filed lawsuits against coal, gas oil and petroleum companies. These suits allege damages for contributions to, or failure to disclose the impact of, climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions both in the United States and globally. Though we are not currently a party to any such lawsuit, these suits present uncertainty regarding the extent to which companies engaged in oil and gas production face an increased risk of liability stemming from climate change, which risk would also adversely impact the oil and gas industry and impact demand for our services. The ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending any potential similar lawsuits in the future. See “Business and Properties—Regulation of GHG Emissions (Climate Change)” for a further description of the laws and regulations that affect us. Separately, plaintiffs have also targeted various governments, arguing that their actions to-date on fossil fuel and/or climate policy violate human or other legal rights; to the extent such litigation is successful, it may result in additional legal restrictions on the production or consumption of fossil fuels, which may adversely impact our business.

Current wording

Increasing attention to global climate change has resulted in increased investor attention and an increased risk of public and private litigation, which could increase our costs or otherwise adversely affect our business. Governmental and other entities in various states, such as California and New York, have filed lawsuits against coal, gas oil and petroleum companies. These suits allege damages for contributions to, or failure to disclose the impact of, climate change, and the plaintiffs are seeking unspecified damages and abatement under various tort theories. Similar lawsuits may be filed in other jurisdictions both in the United States and globally. Though we are not currently a party to any such lawsuit, these suits present uncertainty regarding the extent to which companies engaged in oil and gas production face an increased risk of liability stemming from climate change, which risk would also adversely impact the oil and gas industry and impact demand for our services. The ultimate outcome and impact to us of any such litigation cannot be predicted with certainty, and we could incur substantial legal costs associated with defending any potential similar lawsuits in the future. See “Business and Properties—Regulation of GHG Emissions (Climate Change)” for a further description of the laws and regulations that affect us. Separately, plaintiffs have also targeted various governments, arguing that their actions to-date on fossil fuel and/or climate policy violate human or other legal rights. For example, in December 2024, the Montana Supreme Court ruled in favor of plaintiffs and found that the environmental protection language in the state constitution precluded the state from ignoring the impact of greenhouse gas emissions in connection with permitting and other agency actions. While the ultimate impacts of this ruling are uncertain, this and any other successful litigation may result in additional legal restrictions on the production or consumption of fossil fuels, which may adversely impact our business.

Previous wording

In October 2015, the EPA issued a new lower National Ambient Air Quality Standard (“NAAQS”) for ground level ozone of 70 parts per billion. In 2017, the EPA designated certain counties in southeastern New Mexico and West Texas located in the Permian Basin attainment/unclassifiable for the 2015 ozone NAAQS. However, in June 2022, EPA announced that it is considering a discretionary redesignation for these counties based on current monitoring data and other air quality factors. If the Permian Basin counties in which we operate were redesignated as nonattainment areas, this could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.

Current wording

In October 2015, the EPA issued a new lower National Ambient Air Quality Standard (“NAAQS”) for ground level ozone of 70 parts per billion. In 2017, the EPA designated certain counties in southeastern New Mexico and West Texas located in the Permian Basin attainment/unclassifiable for the 2015 ozone NAAQS. However, in June 2022, EPA announced that it is considering a discretionary redesignation for these counties based on current monitoring data and other air quality factors, however EPA has yet to move forward with any redesignation. If the Permian Basin counties in which we operate were redesignated as nonattainment areas, this could subject us to increased regulatory burdens in the form of more stringent emission controls, emission offset requirements and increased permitting delays and costs.

Previous wording

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the Clean Air Act (the “CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal government has also increased regulation of methane from oil and gas facilities in recent years. For example, in 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In December 2023, the EPA announced finalized rules proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. The proposed rule would establishing more stringent standards of performance for sources that commence construction, modification or reconstruction after the date the proposed rule was published in the Federal Register and emissions guidelines to inform state plans to establish similar standards for existing sources. The BLM also issued a proposed rule in November 2022 to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. If finalized, these increasingly stringent methane and VOC requirements on new facilities, or the application of new requirements to existing facilities, could result in additional restrictions on our operations and increased compliance costs, which could be significant. Additionally, the Inflation Reduction Act, adopted in 2022, imposes several new requirements on oil and gas operators, including a fee for leaks or venting of methane, starting at $900 per ton in 2024 and rising to $1,500 per ton in and after 2026, from certain facilities. The act also appropriates significant federal funding for renewable energy initiatives. In January 2024, EPA issued a proposed rule to implement the emissions charge with a proposed effective date in 2025 for reporting year 2024 emissions. These developments may make it harder for the oil and gas industry to attract capital. Given the long-term trend toward increasing regulation, we expect there will be additional future federal GHG regulations of the oil and gas industry.

Current wording

In the United States, no comprehensive climate change legislation has been implemented at the federal level. However, following the U.S. Supreme Court finding that greenhouse gas (“GHG”) emissions constitute a pollutant under the Clean Air Act (the “CAA”), the EPA has adopted regulations that, among other things, establish construction and operating permit reviews for emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the United States, and together with the Department of Transportation (the “DOT”), implement GHG emissions limits on vehicles manufactured for operation in the United States. The federal government has also increased regulation of methane from oil and gas facilities in recent years. For example, in 2016, the EPA issued regulations under NSPS OOOOa that require operators to reduce methane and VOC emissions from new, modified and reconstructed crude oil and natural gas wells and equipment located at natural gas production gathering and booster stations, gas processing plants and natural gas transmission compressor stations. In December 2023, the EPA announced finalized rules proposed a rule to further reduce methane and VOC emissions from new and existing sources in the oil and natural gas sector. The proposed rule would establishing more stringent standards of performance for sources that commence construction, modification or reconstruction after the date the proposed rule was published in the Federal Register and emissions guidelines to inform state plans to establish similar standards for existing sources. The BLM also issued a proposed rule in November 2022 to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities on federal and American Indian leases. If finalized, these increasingly stringent methane and VOC requirements on new facilities, or the application of new requirements to existing facilities, could result in additional restrictions on our operations and increased compliance costs, which could be significant. Additionally, the Inflation Reduction Act, adopted in 2022, imposes several new requirements on oil and gas operators, including a fee for leaks or venting of methane, starting at $900 per ton in 2024 and rising to $1,200 per ton in 2025, and to

Previous wording

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, the New Mexico Oil Conservation Commission has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO 2 GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector. At COP28, the international community expanded on these ambitions with an agreement to look at transitioning away from fossil fuels, which may result in additional laws or regulations on the production or consumption of the fuels we produce. The impact of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the UNFCCC, various COPs or other international conventions cannot be predicted at this time. However, to the extent these developments result in new restrictions on oil and gas operations, increase operational costs, or otherwise reduce the demand for oil and gas, they could have a material adverse effect on our business.

Current wording

Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. For example, the New Mexico Oil Conservation Commission has adopted regulations to restrict the venting or flaring of methane from both upstream and midstream operations. Internationally, the United Nations-sponsored “Paris Agreement” requires member states to individually determine and submit non-binding emissions reduction targets every five years after 2020. While President Trump has initiated action to withdraw the United States from the Paris Agreement, this withdrawal is not immediate and may animate stronger actions by various other policymakers.

Previous wording

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (“GFANZ”) announced that commitments from over 450 firms across 45 countries had resulted in over $130 trillion in capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero emissions by 2050. There is also a risk that financial institutions will be required to adopt policies that have the effect of reducing the funding provided to the fossil fuel sector. Various U.S. financial regulators have announced that they are considering climate-related regulations and, separately, the Federal Reserve has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. In November 2021, the Federal Reserve issued a statement in support of the efforts of the NGFS to identify key issues and potential solutions for the climate-related challenges most relevant to central banks and supervisory authorities. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Current wording

There are also increasing financial risks for fossil fuel producers as shareholders currently invested in fossil-fuel energy companies may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

Previous wording

Additionally, the SEC has proposed new rules relating to the disclosure of a range of climate-change-related physical and transition risks, data and opportunities. The proposed rule contains several new disclosure obligations, including (i) disclosure on an annual basis of a registrant’s scope 1 and scope 2 greenhouse gas emissions, (ii) third-party independent attestation of the same for accelerated and large accelerated filers, (iii) for some registrants, disclosure on an annual basis of a registrant’s scope 3 greenhouse gas emissions for accelerated and large accelerated filers, (iv) disclosure on how the board of directors and management oversee climate-related risks and certain climate-related governance items, (v) disclosure of information related to a registrant’s climate-related targets, goals and/or transitions plans and (vi) disclosure on whether and how climate-related events and transition activities impact line items above a threshold amount on a registrant’s consolidated financial statements, including the impact of the financial estimates and the assumptions used. The SEC originally planned to issue a final rule by October 2022, but according to the SEC’s updated rulemaking agenda, a final rule is now expected to be issued in spring 2024. While we would likely be subject to the longer proposed phase-in for the reporting requirements as an emerging growth company, we are currently assessing this rule and cannot predict the costs of implementation or any potential adverse impacts resulting from the rule should it be adopted as proposed; however, we expect these costs to be substantial. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

Current wording

Additionally, various policymakers (including the SEC and the State of Colorado) have adopted or are considering adopting rules requiring the disclosure of certain climate-related information. While certain of these rules have been stayed or challenged, any such requirements may require us to incur additional costs or divert management’s attention. In addition, enhanced climate disclosure requirements could accelerate the trend of certain stakeholders and lenders restricting or seeking more stringent conditions with respect to their investments in certain carbon intensive sectors.

Previous wording

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other sectors have led to lower natural gas and oil representation in certain key equity market indices. Some investors, including certain pension funds, private equity funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop directly funding or raising capital for hydrocarbon extraction, transportation or refining. If this negative sentiment continues or worsens, it may reduce the availability of capital funding for potential development projects or other strategic or operational purposes, any of which could have a material adverse effect our financial condition, results of operations, cash flows and ability to pay distributions on our common units.

Current wording

Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other sectors have led to lower natural gas and oil representation in certain key equity market indices. Some investors, including certain pension funds, private equity funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the natural gas and oil sector based on social and environmental considerations. Certain other stakeholders have pressured commercial and investment banks to stop directly funding or raising capital for hydrocarbon extraction, transportation or refining. If this negative sentiment continues or worsens, it may reduce the availability of capital funding for potential development projects or other strategic or operational purposes, any of which could have a material adverse effect on our financial condition, results of operations, cash flows and ability to pay distributions on our common units.

Previous wording

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. Nearly all of our operated wells are drilled conventionally; however, from time to time, a small percentage of our wells are horizontally completed.

Current wording

Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas from dense subsurface rock formations. Hydraulic fracturing involves the injection of water, sand or alternative proppant and chemicals under pressure into targeted geological formations to fracture the surrounding rock and stimulate production. A significant portion of our operated wells are drilled conventionally; however, from time to time, a portion of our wells are horizontally completed. This will be especially true in the Williston Basin.

Previous wording

Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. In addition, the use, treatment and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs or other adverse effects on our business, results of operations and financial condition. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition.

Current wording

Water is an essential component of shale oil and natural gas development during both the drilling and hydraulic fracturing processes. Our access to water to be used in these processes may be adversely affected due to reasons such as periods of extended drought, private, third-party competition for water in localized areas or the implementation of local or state governmental programs to monitor or restrict the beneficial use of water subject to their jurisdiction for hydraulic fracturing to assure adequate local water supplies. In addition, treatment and disposal of water is becoming more highly regulated and restricted. Thus, our costs for obtaining and disposing of water could increase significantly. In addition, the use, treatment and disposal of water has become a focus of certain investors and other stakeholders who may seek to engage with us on this and other environmental matters, which may result in activism, negative reputational impacts, increased costs or other adverse effects on our business, results of operations and financial condition. Our inability to locate or contractually acquire and sustain the receipt of sufficient amounts of water could adversely impact our exploration and production operations and have a corresponding adverse effect on our business, results of operations and financial condition. Finally, our operations could be impaired if we are unable to recycle or dispose of the water we produce in an economical and environmentally safe manner.

Previous wording

Our general partner has control over all decisions related to our operations. Bob R. Simpson, our Chief Executive Officer and Chairman, Brent W. Clum, our President of Business Operations, Chief Financial Officer and Director, and Keith A. Hutton, our President of Production and Development and Director (collectively, the “Founders”) own a majority interest in the membership interests in the sole member of our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty, in certain cases, to manage our general partner at the direction of MSOG, which is majority-owned and controlled by the Founders. As a result of these relationships, conflicts of interest may arise in the future between the Founders and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our common unitholders. These conflicts include, among others, the following:

Current wording

Our general partner has control over all decisions related to our operations. Bob R. Simpson, our Chief Executive Officer and Chairman, Brent W. Clum, our President of Business Operations, Chief Financial Officer and Director, and Keith A. Hutton, a Director (collectively, the “Founders”) own a majority interest in the membership interests in the sole member of our general partner. Although our general partner has a duty to manage us in a manner that is not adverse to the best interests of us and our unitholders, the executive officers and directors of our general partner also have a duty, in certain cases, to manage our general partner at the direction of MSOG, which is majority-owned and controlled by the Founders. As a result of these relationships, conflicts of interest may arise in the future between the Founders and their respective affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of us and our common unitholders. These conflicts include, among others, the following:

Previous wording

Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of the each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our Credit Facility, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.

Current wording

Our partnership agreement provides that we distribute each quarter all of our available cash, which we define as cash on hand at the end of each quarter, less reserves established by our general partner. As a result, we expect to rely primarily upon our cash reserves and external financing sources, including the issuance of additional common units and other partnership securities and borrowings under our Credit Facility, to fund future acquisitions and finance our growth. To the extent we are unable to finance growth with our cash reserves and external sources of capital, the requirement in our partnership agreement to distribute all of our available cash may impair our ability to grow.

Previous wording

Our general partner has control over all decisions related to our operations. Since affiliates of our general partner (including the Founders) collectively own and control the voting of an aggregate of approximately 37% of our outstanding common units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. However, our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the affiliates of our general partner (including the Founders)). Assuming we do not issue any additional common units and the affiliates of our general partner (including the Founders) do not transfer any of their common units, the affiliates of our general partner (including the Founders) will generally have the ability to significantly influence any amendment to our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders. Furthermore, the goals and objectives of the affiliates of our general partner (including the Founders) that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “—Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.”

Current wording

Our general partner has control over all decisions related to our operations. Since affiliates of our general partner (including the Founders) collectively own and control the voting of an aggregate of approximately 31% of our outstanding common units, the other unitholders will not have an ability to influence any operating decisions and will not be able to prevent us from entering into any transactions. However, our partnership agreement can generally be amended with the consent of our general partner and the approval of the holders of a majority of our outstanding common units (including common units held by the affiliates of our general partner (including the Founders). Assuming we do not issue any additional common units and the affiliates of our general partner (including the Founders) do not transfer any of their common units, the affiliates of our general partner (including the Founders) will generally have the ability to significantly influence any amendment to our partnership agreement, including our policy to distribute all of our cash available for distribution to our unitholders. Furthermore, the goals and objectives of the affiliates of our general partner (including the Founders) that hold our common units relating to us may not be consistent with those of a majority of the other unitholders. Please read “—Our general partner and its affiliates own a controlling interest in us and will have conflicts of interest with, and owe limited duties to, us, which may permit them to favor their own interests to the detriment of us and our unitholders.”

Previous wording

The public unitholders will be very limited in their ability to remove our general partner without its consent because the Founders own sufficient units to be able to strongly influence a vote with respect to the removal of our general partner. The vote of the holders of at least 662⁄3% of all outstanding units voting together as a single class is required to remove our general partner. The Founders own approximately 26% of our outstanding voting units.

Current wording

The public unitholders will be very limited in their ability to remove our general partner without its consent because the Founders own sufficient units to be able to strongly influence a vote with respect to the removal of our general partner. The vote of the holders of at least 66.67% of all outstanding units voting together as a single class is required to remove our general partner. The Founders own approximately 22% of our outstanding voting units.

Previous wording

Affiliates of our general partner (including the Founders) own 11,470,901 common units, or approximately 37% of our limited partner interest. Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates, which includes the Founders. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Current wording

Affiliates of our general partner (including the Founders) own 12,947,878 common units, or approximately 31% of our limited partner interest. Under our partnership agreement, we have agreed to register for resale under the Securities Act and applicable state securities laws any common units or other partnership interests proposed to be sold by our general partner or any of its affiliates, which includes the Founders. The sale of these units in the public markets could have an adverse impact on the price of the common units or on any trading market that may develop.

Previous wording

If at any time our general partner and its affiliates own more than 80% of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. Affiliates of our general partner own approximately 37% of our common units.

Current wording

If at any time our general partner and its affiliates own more than 80% of the then outstanding common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There is no restriction in our partnership agreement that prevents our general partner from causing us to issue additional common units and then exercising its call right. If our general partner exercises its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. Affiliates of our general partner own approximately 31% of our common units.

Previous wording

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units, may be modified by administrative, legislative or judicial interpretation. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

Current wording

Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships or an investment in our common units, including elimination of partnership tax treatment for certain publicly traded partnerships.

Previous wording

Moreover, upon the sale, exchange or other disposition of a common unit by a non-U.S. unitholder, the transferee is generally required to withhold 10% of the amount realized on such sale, exchange or other disposition if any portion of the gain on such sale, exchange or other disposition would be treated as effectively connected with a U.S. trade or business. The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. The U.S. Department of the Treasury and the IRS have provided that these rules generally apply to transfers of our common units occurring on or after January 1, 2023. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

Current wording

The U.S. Department of the Treasury and the IRS have issued final regulations providing guidance on the application of these rules for transfers of certain publicly traded partnership interests, including transfers of our common units. Under these regulations, the “amount realized” on a transfer of our common units will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and such broker will generally be responsible for the relevant withholding obligations. Distributions to non-U.S. unitholders may also be subject to additional withholding under these rules to the extent a portion of a distribution is attributable to an amount in excess of our cumulative net income that has not previously been distributed. Non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

Previous wording

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in New Mexico, Texas and Colorado, among other states. New Mexico and Colorado each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.

Current wording

In addition to federal income taxes, our common unitholders will likely be subject to other taxes, such as state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes imposed by the various jurisdictions in which we do business or own property now or in the future, even if the unitholder does not live in any of those jurisdictions. Our common unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own property or conduct business in New Mexico, Texas, Colorado, Montana, Mississippi and North Dakota. New Mexico, Colorado, Montana, Mississippi and North Dakota each impose a personal income tax. Texas does not currently impose a personal income tax on individuals, but it does impose an entity level tax (to which we will be subject) on corporations and other entities. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal or corporate income tax. It is the responsibility of each unitholder to file its own federal, state and local tax returns, as applicable.