What changed in this filing

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Item 1A. Risk Factors

2024-02-22 compared with 2023-02-23 · 90 added, 113 removed, 435 unchanged (32% of the section changed)

45 unchanged sentences

All of the decisions regarding implementation of such projects, including drilling or exploration on any unleased and undeveloped acreage, will be made by third parties.

Our ability to increase reserves through future acquisitions is limited by restrictions on our use of operating cash and limited partnership interests for acquisitions and by our General Partner's obligation to use all reasonable efforts such as NPIs to avoid unrelated business taxable income.

Our ability to increase reserves through future acquisitions is limited by restrictions on our use of operating cash and limited partnership interests for acquisitions and by our General Partner's obligation to use all reasonable efforts (such as limiting acquisitions to acquisitions of NPIs and royalty interests) to avoid unrelated business taxable income.

In addition, the ability of affiliates of our General Partner to pursue business opportunities for their own accounts without tendering them to us in certain circumstances may reduce the acquisitions presented to us for consideration.

Acreage must be drilled before lease expiration, generally within three years, in order to hold the acreage by production.

Our operators ’

failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities.

Our operators ’ failure to drill sufficient wells to hold acreage may result in the deferral of prospective drilling opportunities.

In addition, our ORRIs may terminate if the underlying acreage is not drilled before the expiration of the applicable lease or if the lease otherwise terminates.

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In addition, even if production or drilling is established during such primary term, if production or drilling ceases on the leased property, the lease typically terminates, subject to certain exceptions.

Any reduction in our operators’

drilling programs, either through a reduction in capital expenditures or the unavailability of equipment, services, or supplies, could result in the expiration of existing leases.

Any reduction in our operators’ drilling programs, either through a reduction in capital expenditures or the unavailability of equipment, services, or supplies, could result in the expiration of existing leases.

If the lease governing any of our mineral interests expires or terminates, all development rights typically revert back to us, and we may seek new lessees to explore and develop such mineral interests or in some states remain unleased.

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In connection with these acquisitions, we are conveyed record title to mineral and royalty interests.

Due to such changes in ownership of mineral interests, the operator of the underlying property has the right, at such operator’s discretion, to investigate and verify the title and ownership of mineral and royalty interests with respect to the properties it operates.

If any title or ownership issues are not resolved to its reasonable satisfaction in accordance with customary industry standards, the operator has the right to suspend payment of the related royalty.

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However, we cannot guarantee finding a suitable replacement operator in such a circumstance and if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time.

In addition, the outgoing operator could be subject to a bankruptcy proceeding under Title 11 of the United States Code (the “Bankruptcy Code”), in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise at risk.

In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have an extended period of time to decide whether to ultimately reject or assume the lease, which could significantly delay or prevent the execution of a new lease or the assignment of the existing lease to a replacement operator.

In general, in a proceeding under the Bankruptcy Code, the bankrupt operator would have an extended period of time to decide whether to ultimately reject or assume the lease, which could significantly delay or prevent the execution of a new lease or the assignment of the existing lease to a replacement operator.

In the event that an operator rejects the lease, our ability to collect amounts owed to us would be substantially delayed, and our ultimate recovery may be only a fraction of the amount owed or nothing.

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If we enter into hedging arrangements in the future, it may limit our ability to realize the benefit of rising prices and may result in hedging losses.

Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators ’

ability to succeed.

Competition in the oil and natural gas industry is intense, which may adversely affect our and our operators ’ ability to succeed.

The oil and natural gas industry is intensely competitive, and the operators of our properties compete with other companies that may have greater resources or greater access to capital.

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In addition, these companies may have a greater ability to continue exploration activities during periods when market prices of oil and natural gas are low.

Our operators’

larger competitors may be able to better address the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which could adversely affect our operators’

competitive position.

Our operators may have access to fewer financial and human resources than many companies in our operators’

industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Our operators’ larger competitors may be able to better address the burden of present and future federal, state, local and other laws and regulations more easily than our operators can, which could adversely affect our operators’ competitive position.

Our operators may have access to fewer financial and human resources than many companies in our operators’ industry and may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.

Furthermore, the oil and natural gas industry has experienced recent consolidation amongst some operators, which has resulted in certain instances of combined companies with larger resources.

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Regulators have the ability, directly or indirectly, to limit production from our properties, and such limitations or changes in those limitations could negatively impact us in the future.

Cyber incidents or attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our business may be adversely impacted.

Cyber incidents or attacks targeting our systems and infrastructure used by the oil and natural gas industry may adversely impact our operations, and if we are unable to obtain and maintain adequate protection of our data, our business may be adversely impacted.

We and our operators increasingly rely on information technology systems to operate our respective businesses, and the oil and natural gas industry depends on digital technologies in exploration, development, production, and processing activities.

Threats to information technology systems associated with cybersecurity risks and cyber incidents or attacks continue to grow.

Our technologies, systems, networks, and those of the operators of our properties, vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities.

Our technologies, systems, networks, including third party software, cloud services and other internally and externally hosted hardware and software platforms, and those of the operators of our properties, vendors, suppliers, and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of business activities.

In addition, certain cyber incidents, such as surveillance, may remain undetected for some period of time.

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Sustained levels of high inflation have likewise caused the U.S.

Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which- or the combination thereof-could hurt the financial and operating results of our operators’

Federal Reserve and other central banks to increase interest rates, which could have the effects of raising the cost of capital and depressing economic growth, either of which, or the combination thereof, could hurt the financial and operating results of our operators’ businesses.

If our operators are unable to secure the goods, services and labor necessary for their operations at reasonable costs, their exploration and development activities could be delayed or restricted, which in turn could have a material adverse effect on our financial condition, results of operations and free cash flow.

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The following is a summary of some of the existing environmental laws, rules and regulations that apply to oil and natural gas operations, and that may indirectly affect our cash flow.

is required), and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

The term “hazardous substance”

is specifically defined to exclude petroleum, including crude oil and any fraction thereof, natural gas and natural gas liquids.

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability (i.e., no showing of “fault” is required), and under certain circumstances, joint and several liability, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment.

The term “hazardous substance” is specifically defined to exclude petroleum, including crude oil and any fraction thereof, natural gas and natural gas liquids.

Despite this exclusion, certain materials that are commonly used in connection with oil and natural gas operations are considered to be hazardous substances under CERCLA.

Responsible persons include the current or former owner or operator of the site where the release occurred, and anyone who disposed of or arranged for the disposal of a hazardous substance released at the site, regardless of whether the disposal of hazardous substances was lawful at the time of the disposal.

Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances, cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for certain health studies.

Under CERCLA, such persons may be subject to strict, joint and several liabilities for the costs of investigating releases of hazardous substances, cleaning up the hazardous substances that have been released into the environment, damages to natural resources and certain health studies.

In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

The operators of our properties may be responsible under CERCLA for all or part of these costs.

Although we are not an operator, our ownership of royalty interests could cause us to be responsible for all or part of such costs to the extent that CERCLA imposes such responsibilities on such parties as “owners.”

The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.

Drilling fluids, produced water and many other wastes associated with the exploration, development and production of oil or natural gas are currently excluded from regulation under RCRA’s hazardous waste provisions.

However, it is possible that certain oil and natural gas exploration and production wastes could be classified as hazardous wastes in the future.

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Many of our properties have produced oil and/or natural gas for many years.

We have no knowledge of current and prior operators’

procedures with respect to the disposal of oil and natural gas wastes.

We have no knowledge of current and prior operators’ procedures with respect to the disposal of oil and natural gas wastes.

Hydrocarbons or other solid or hazardous wastes may have been released on or under our properties by the operators or prior operators.

Our properties and the materials disposed or released on, at, under or from them may be subject to CERCLA, RCRA and analogous state laws, and removal or remediation of such materials could be required by a governmental authority.

The Federal Clean Air Act (“CAA”) and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and other requirements, such as emissions controls.

Existing laws and regulations and possible future laws and regulations may require our operators to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions and may impose stringent air permit requirements or mandate the use of specific equipment or technologies to control emissions.

Environmental Protection Agency (“EPA”) continues to develop New Source Performance standards for oil and natural gas facilities.

Most recently, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector.

Environmental Protection Agency (“EPA”) continues to develop New Source Performance standards for oil and natural gas facilities.

On May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new, modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector.

However, on August 13, 2020, in response to an executive order by former President Trump, the EPA amended the New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether.

On June 30, 2021, President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments, with the exception of some technical changes, thereby reinstating the prior standards.

The EPA expects owners and operators of regulated sources to take “immediate steps”

to comply with these standards.

Additionally, on November 15, 2021, the EPA published a proposed rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations.

On December 6, 2022, the EPA published a supplemental proposal to strengthen the emission reduction requirements, which would, among other things, expand leak detection requirements and tighten flaring restrictions.

The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards.

Additionally, on December 2, 2023, the EPA announced a final rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations.

Additionally, on April 17, 2023, the EPA agreed in a consent decree to issue a proposed rule by December 10, 2024 that either revises its emission standards for hazardous air pollutants from oil and natural gas production activities or determines that no revision is necessary.

Federal changes will affect state air permitting programs in states that administer the federal CAA under a delegation of authority, including states in which we have operations.

The Federal Water Pollution Control Act (the “Clean Water Act”

or “CWA”) and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands.

The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers (“USACOE”).

On June 29, 2015, the EPA and the USACOE jointly promulgated a final rule redefining the scope of “Waters of the United States”

(“WOTUS”), which would have made additional waters subject to the jurisdiction of the Clean Water Act.

However, on October 22, 2019, the agencies published a final rule to repeal the 2015 WOTUS rule, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rule, and significantly reducing the waters subject to federal regulation under the CWA.

On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015.

Meanwhile, in October 2022, the Supreme Court heard oral argument in a case addressing the proper test for determining whether wetlands are “waters of the United States.”

As a result of such recent developments, substantial uncertainty exists regarding the scope of waters protected under the CWA.

To the extent the rules expand the range of properties subject to the CWA’s jurisdiction, our operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could cause delays in development and/or increase the cost of development and operation of those properties.

Spill prevention, control, and countermeasure (“SPCC”) regulations promulgated under the CWA and later amended by the Oil Pollutions Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines.

These new standards, to the extent implemented, as well as any future laws and their implementing regulations, may require our operators to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

We cannot predict the final regulatory requirements or the cost to our operators to comply with such requirements with any certainty.

The Federal Water Pollution Control Act (the “Clean Water Act” or “CWA”) and analogous state laws impose restrictions and strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances into regulated waters, including wetlands.

On June 29, 2015, the EPA and the USACOE jointly promulgated a final rule expanding the scope of “Waters of the United States” (“WOTUS”), which would have made additional waters subject to the jurisdiction of the Clean Water Act.

However, on October 22, 2019, the agencies published a final rule to repeal the 2015 WOTUS rule, and then, on April 21, 2020, the EPA and the USACOE published a final rule replacing the 2015 rule and significantly reducing the waters subject to federal regulation under the CWA.

On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the USACOE published a final rule that would restore water protections that were in place prior to 2015.

However, on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected under the CWA.

On September 8, 2023, the EPA and the USACOE published a final rule conforming their regulations to the decision.

These recent actions have provided some clarity.

To the extent the EPA and the USACOE broadly interpret their jurisdiction and expand the range of properties subject to the CWA’s jurisdiction, our operators could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas, which could cause delays in development and/or increase the cost of development and operation of those properties.

Spill prevention, control, and countermeasure (“SPCC”) regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or threatening waters of the United States or adjoining shorelines.

For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach jurisdictional waters, must develop, implement, and maintain SPCC Plans.

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If endangered or threatened species are located on our properties, operations on those properties could be prohibited or delayed or expensive mitigation may be required.

Also, the United States Fish and Wildlife Service (“USFWS”) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of threatened or endangered species.

A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access, development or operations (including prevent oil and natural gas exploration or production).

Additionally, the designation of previously unprotected species in areas where we operate as endangered or threatened could result in the imposition of restrictions on our operators and consequently have a material adverse effect on our business.

Oil and natural gas operations are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes and their implementing regulations.

The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under section 112(r) of the CAA and similar state statutes may require disclosure of information about hazardous materials used, produced or otherwise managed during operation.

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The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions.

to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.

However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process.

Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process.

For example, the EPA has taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II”

Underground Injection Control wells under the SDWA.

Future federal laws or regulations could require hydraulic fracturing operations to meet permitting and financial assurance requirements, adhere to certain construction specifications, fulfill monitoring, reporting and recordkeeping obligations and meet plugging and abandonment requirements.

Such federal legislation or regulation could lead to operational delays or increased operating costs and could result in additional regulatory burdens that could make it more difficult to perform hydraulic fracturing.

In addition, on March 26, 2015, the Bureau of Land Management (“BLM”) published a final rule governing hydraulic fracturing on federal and Indian lands.

The rule requires public disclosure of chemicals used in hydraulic fracturing, implementation of a casing and cementing program, management of recovered fluids, and submission to the BLM of detailed information about the proposed operation, including wellbore geology, the location of faults and fractures, and the depths of all usable water.

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Accordingly, on December 29, 2017, the BLM published a final rule to rescind the 2015 hydraulic fracturing rule.

State and environmental groups have challenged this rollback.

A coalition of environmentalists, tribal advocates and the State of California filed lawsuits challenging the rule rescission.

Also, on September 28, 2018, the BLM published a final rule to revise the 2016 methane rule;

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On November 28, 2022, the BLM announced a proposed replacement rule to reduce the waste of natural gas from venting, flaring and leaks during oil and gas production activities on federal and Indian lands, which would require the use of upgraded equipment in some cases and would place time and volume limits on royalty-free flaring.

Also, on July 24, 2023, the BLM published a proposed rule to update its oil and gas leasing regulations, which would increase bonding requirements and raise royalty rates.

At this time, it is uncertain when, or if, the above rules will be implemented or if new requirements will be adopted.

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Certain state agencies, including those in Texas and Oklahoma, have implemented regulations authorizing the imposition of certain limitations on existing wells if seismic activity increases in the area of an injection well, including a temporary injection ban.

pursuant to which the agency reviews new disposal well applications and may restrict operations at existing wells.

For example, in Oklahoma, the Oklahoma Corporations Commission (“OCC”) has implemented a variety of measures, including the adoption of the National Academy of Science’s “traffic light system,” pursuant to which the agency reviews new disposal well applications and may restrict operations at existing wells.

Beginning in 2013, the OCC has ordered the reduction of disposal volumes into the Arbuckle formation.

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The adoption of climate change legislation or regulations could result in increased operating costs and reduced demand for the oil and natural gas production from our properties.

In recent years, federal, state, and local governments have taken steps to reduce emissions of greenhouse gases (“GHGs”).

On August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA”), which includes billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration.

These incentives could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, oil and natural gas and adversely impact our business.

In recent years, federal, state, and local governments have taken steps to reduce emissions of greenhouse gases (“GHGs”).

For example, the Infrastructure Investment and Jobs Act of 2021 and the Inflation Reduction Act of 2022 (“IRA”) include billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration.

The EPA has proposed ambitious rules to reduce harmful air pollutant emissions, including GHGs, from light-, medium-, and heavy-duty vehicles beginning in model year 2027.

These incentives and regulations could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, oil and natural gas and adversely impact our business.

In addition, the IRA imposes the first ever federal fee on the emission of GHGs through a methane emissions charge.

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Calculation of the fee is based on certain thresholds established in the IRA.

The methane emissions charge could increase our operators’

costs, which could adversely impact our business, financial condition and cash flows.

On January 12, 2024, the EPA announced a proposed rule to implement the methane emissions charge.

The methane emissions charge could increase our operators’ costs, which could adversely impact our business, financial condition and cash flows.

The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and almost half of the states have taken measures to reduce GHG emissions primarily through the development of GHG emission inventories and/or regional GHG cap and trade programs.

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In addition, states have imposed increasingly stringent requirements related to the venting or flaring of natural gas during oil and natural gas operations.

In addition, the United States has been involved in international negotiations regarding greenhouse gas reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”).

was among approximately 195 nations that signed an international accord in December 2015, the so called Paris Agreement, which became effective on November 4, 2016, with the objective of limiting greenhouse gas emissions.

Although the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which went into effect on February 19, 2021.

On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels by 2030.

In November 2021, in connection with Glasgow Climate Pact, the United States and other world leaders made further commitments to reduce greenhouse gas emissions, including reducing global methane emissions by at least 30% by 2030.

In addition, the United States has been involved in international negotiations regarding GHG reductions under the United Nations Framework Convention on Climate Change (“UNFCCC”).

On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG emissions by 50-52 percent below 2005 levels by 2030.

In November 2021, in connection with Glasgow Climate Pact, the United States and other world leaders made further commitments to reduce GHG emissions, including reducing global methane emissions by at least 30% by 2030 from 2020 levels.

More than 150 countries have now signed on to this pledge.

Most recently, at the 28th Conference of the Parties in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030.

Many state and local leaders have stated their intent to intensify efforts to support the international climate commitments.

Although these international commitments are not directly binding on companies, additional GHG reduction regulatory requirements may be issued in an effort to help meet the U.S.

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In addition, spurred by increasing concerns regarding climate change, the oil and natural gas industry faces growing demand for corporate transparency and a demonstrated commitment to sustainability goals.

Environmental, social, and governance (“ESG”) goals and programs, which typically include extralegal targets related to environmental stewardship, social responsibility, and corporate governance, have become an increasing focus of investors and shareholders across the industry.

While reporting on ESG metrics remains voluntary, access to capital and investors is likely to favor companies with robust ESG programs in place.

In March 2022, the SEC proposed new rules relating to the disclosure of a range of climate-related risks and other information.

To the extent this rule is finalized as proposed, the Partnership, our operators and/or our customers could incur increased costs related to the assessment and disclosure of climate-related information.

Enhanced climate disclosure requirements could also accelerate any trend by certain stakeholders and capital providers to restrict or seek more stringent conditions with respect to their financing of certain carbon intensive sectors.

Ultimately, these initiatives could make it more difficult to secure funding for exploration and production activities.

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Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages.

Extreme weather conditions can interfere with our operators’

activities and increase their costs and damage resulting from extreme weather may not be fully insured.

Extreme weather conditions can interfere with our operators’ activities and increase their costs and damage resulting from extreme weather may not be fully insured.

However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

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The outcome of pending litigation related to the Dakota Access Pipeline and any related executive orders could have a material adverse effect on our revenue and cash distributions.

In connection with ongoing litigation initiated in February 2017 by the Standing Rock Sioux Tribe and the Cheyenne River Sioux Tribe contesting the validity of the process used by the USACOE to permit the Dakota Access Pipeline, on July 6, 2020, the United States District Court for the District of Columbia (the “Court”) issued an order vacating the USACOE’s easement for the Dakota Access Pipeline and requiring that the pipeline be shut down by August 5, 2020.

Dakota Access, LLC and the USACOE appealed the decision.

On July 14, 2020, the Court of Appeals granted a temporary administrative stay, and on January 26, 2021, the Court of Appeals affirmed that part of the lower court decision vacating the USACOE’s easement while it prepares a new environmental impact statement, but reversed the lower court’s order to shut down the pipeline.

Since then, both the Biden Administration and the Court have declined to shut down the pipeline, and on June 22, 2021, the Court dismissed the subject lawsuit.

The Court noted, however, that future challenges were possible depending on the outcome of the ongoing environmental study, which is expected to be completed in Spring 2023.

The Court noted, however, that future challenges were possible depending on the outcome of the ongoing environmental study, which the USACOE issued in draft form on September 8, 2023.

Accordingly, the continued operation of Dakota Access Pipeline in the future is uncertain.

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We are dependent on service providers who assist us with providing Schedule K-1 tax statements to our unitholders.

There are a very limited number of service firms that currently perform the detailed computations needed to provide each unitholder with estimated depletion and other tax information to assist the unitholder in various United States income tax computations.

federal income tax computations.

There are also very few publicly traded limited partnerships that need these services.

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Tax Risk Factors

The tax consequences to a unitholder of the ownership and sale of common units will depend in part on the unitholder ’

s tax circumstances.

Each unitholder should consult such unitholder ’

s own tax advisor about the federal, state and local tax consequences of the ownership of common units.

The tax consequences to a unitholder of the ownership and sale of common units will depend in part on the unitholder ’ s tax circumstances.

Each unitholder should consult such unitholder ’ s own tax advisor about the federal, state and local tax consequences of the ownership of common units.

We generally do not obtain rulings or assurances from the IRS or state or local taxing authorities on matters affecting us.

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federal income tax laws that affect publicly traded partnerships, including elimination of partnership tax treatment for publicly traded partnerships.

Under current law, we believe that our royalty income is qualifying income for purposes of Section 7704(d)(1)(E) of the Internal Revenue Code (the “Code”).

If the current law remains effective in its current form, we believe we will continue to be able to meet the qualifying income requirement.

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Any such changes could negatively impact the value of an investment in our common units.

The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders ’

allocable share of our net income, in which case our unitholders ’

tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.

For taxable years beginning after December 31, 2017 and ending on or before December 31, 2025, an individual taxpayer may generally claim a deduction in the amount of 20% of its allocable share of certain publicly traded partnership income, including generally, among other items, the net amount of its items of income, gain, deduction, and loss from a publicly traded partnership’s U.S.

The recently enacted 20% deduction for certain pass-through income may not be available for our unitholders ’ allocable share of our net income, in which case our unitholders ’ tax liability with respect to ownership and disposition of our units may be materially higher than if the deduction is available.

trade or business.

Because we own only non-operated, passive mineral and royalty interests, most or all of the income that we now generate, or will generate in the future, may not be “qualifying publicly traded partnership income”

eligible for the 20% deduction.

If the deduction is not available, our unitholders’

tax liability from ownership and disposition of our units may be materially higher than if the deduction is available.

If the deduction is not available, our unitholders’ tax liability from ownership and disposition of our units may be materially higher than if the deduction is available.

We urge our unitholders to consult with their tax advisors regarding the availability of the 20% deduction on any income allocated from us.

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Our unitholders may not be able to deduct losses attributable to their common units.

Any losses relating to our unitholders’

common units will be losses related to portfolio income and their ability to use such losses may be limited.

Our unitholders ’

partnership tax information may be audited.

Any losses relating to our unitholders’ common units will be losses related to portfolio income and their ability to use such losses may be limited.

Our unitholders ’ partnership tax information may be audited.

We will furnish our unitholders with a Schedule K-1 tax statement that sets forth their allocable share of income, gains, losses and deductions.

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This schedule may not yield a result that conforms to statutory or regulatory requirements or to administrative pronouncements of the IRS.

Further, our tax return may be audited, and any such audit could result in an audit of our unitholders’

individual income tax returns as well as increased liabilities for taxes because of adjustments resulting from the audit.

An audit of our unitholders’

returns also could be triggered if the tax information relating to their common units is not consistent with the Schedule K-1 that we are required to provide to the IRS.

Further, our tax return may be audited, and any such audit could result in an audit of our unitholders’ individual income tax returns as well as increased liabilities for taxes because of adjustments resulting from the audit.

An audit of our unitholders’ returns also could be triggered if the tax information relating to their common units is not consistent with the Schedule K-1 that we are required to provide to the IRS.

Our unitholders may have more taxable income or less taxable loss with respect to their common units if the IRS does not respect our method for determining the adjusted tax basis of their common units.

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Our unitholders may have more taxable income or less taxable loss on an ongoing basis if the IRS does not accept our method of allocating depletion deductions.

The Code requires that income, gain, loss and deduction attributable to appreciated or depreciated property that is contributed to a partnership in exchange for a partnership interest be allocated so that the contributing partner is charged with, or benefits from, unrealized gain or unrealized loss, referred to as “Built-in Gain”

and “Built-in Loss,”

respectively, associated with the property at the time of its contribution to the partnership.

Our partnership agreement provides that the adjusted tax basis of the oil and natural gas properties contributed to us is allocated to the contributing partners for the purpose of separately determining depletion deductions.

Any gain or loss resulting from the sale of property contributed to us will be allocated to the partners that contributed the property, in proportion to their percentage interest in the contributed property, to take into account any Built-in Gain or Built-in Loss.

Our partnership agreement provides that the adjusted tax basis of the oil and natural gas properties contributed to us generally is allocated to the contributing partners for the purpose of separately determining depletion deductions.

Any gain or loss resulting from the sale of property contributed to us generally will be allocated to the partners that contributed the property, in proportion to their percentage interest in the contributed property, to take into account any Built-in Gain or Built-in Loss.

This method of allocating Built-in Gain and Built-in Loss is not specifically permitted by the applicable Treasury regulations, and the IRS may challenge this method.

22 unchanged sentences

If a unitholder sells or otherwise disposes of a common unit on or after January 1, 2023, the transferee generally will be required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person.

on such a transfer will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor (and thus determined without regard to any decrease in that transferor’s share of the publicly traded partnership's liabilities).

However, final regulations issued by the Treasury Department on the application of these rules to transfers of certain publicly traded partnership interests, including our common units, provide that the obligation to withhold on a transfer of interests in a publicly traded partnership that is effected through a broker is imposed on the transferor’s broker (instead of the transferee), and the “amount realized” on such a transfer will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor (and thus determined without regard to any decrease in that transferor’s share of the publicly traded partnership's liabilities).

Prospective foreign unitholders should consult their tax advisors regarding the impact of these rules on an investment in our common units.

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No assurance can be given that public health threats will not have a material adverse effect, and that any further spread of COVID-19 and its ongoing variants will not have a material adverse effect, on our business, operations and financial results.

The Partnership may be adversely affected by the global economic instability caused by the military conflict between Russia and Ukraine.

In February 2022, Russian military forces invaded Ukraine, causing a military conflict which has contributed to increased economic uncertainty which may continue in 2023.

An expansion or escalation of this conflict could lead to additional market disruptions, including significant volatility in commodity prices and supply of energy resources along with instability in financial markets.

As a result of the invasion, various economic and trade sanctions have been implemented by countries and private market participants on Russia which have resulted in a lower worldwide supply of oil and natural gas, contributing to a sharp increase in market prices for these commodities.

Despite this increase in market prices for oil and natural gas, such sanctions, and other measures, as well as the existing and potential further responses from Russia or other countries to such sanctions, supply chain disruptions, tensions and military actions, could adversely affect the global economy and financial markets and could adversely affect our business, financial condition and results of operations.

The Partnership may be adversely affected by the international economic instability caused by ongoing global conflicts.

During 2022 and 2023, multiple global military conflicts arose, causing instability in the international economy which may continue into 2024.

Although the length, impact and outcome of these military conflicts are highly unpredictable, an escalation or expansion of any of these conflicts could lead to significant market and other disruptions, including disruptions to the oil and gas industry, significant volatility in commodity prices and supply of energy resources, instability in financial markets, supply chain interruptions, political and social instability and other material and adverse effects on macroeconomic conditions.

It is not possible at this time to predict or determine the ultimate consequences of these ongoing conflicts.

We will continue to incur increased costs as a result of operating as a public company, and our management will continue to devote substantial time to compliance with our public company responsibilities and corporate governance practices.

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If, notwithstanding our efforts to comply with new or changing laws, regulations, and standards, we fail to comply, regulatory authorities may initiate legal proceedings against us, and our business may be harmed.

Further, failure to comply with these laws, regulations and standards may make it more difficult and more expensive for us to obtain directors’

and officers’

liability insurance, which could make it more difficult for us to attract and retain qualified members to serve on our board of directors or committees or as members of senior management.

Further, failure to comply with these laws, regulations and standards may make it more difficult and more expensive for us to obtain directors’ and officers’ liability insurance, which could make it more difficult for us to attract and retain qualified members to serve on our board of directors or committees or as members of senior management.

These rules and regulations are often subject to varying interpretations, in many cases due to their lack of specificity, and, as a result, their application in practice may evolve over time as new guidance is provided by regulatory and governing bodies.

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We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements for a number of important reasons, including those discussed under "Risk Factors" and elsewhere in this report.

Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, public health crises including the worldwide coronavirus (COVID-19) outbreak beginning in early 2020 and its ongoing variants, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations.

Examples of such reasons include, but are not limited to, changes in the price or demand for oil and natural gas, public health crises including the worldwide coronavirus (COVID-19) outbreak beginning in early 2020 and its ongoing variants, the conflict in Ukraine, the conflict between Israel and Hamas, changes in the operations on or development of our properties, changes in economic and industry conditions and changes in regulatory requirements (including changes in environmental requirements) and our financial position, business strategy and other plans and objectives for future operations.

You should read these statements carefully because they may discuss our expectations about our future performance, contain projections of our future operating results or our future financial condition, or state other forward-looking information.

Before you invest, you should be aware that the occurrence of any of the events herein described in "Item 1A –

Risk Factors" and elsewhere in this report and in the Partnership’s other filings with the Securities and Exchange Commission could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.

UNRESOLVED STAFF COMMENTS

Before you invest, you should be aware that the occurrence of any of the events herein described in "Item 1A – Risk Factors" and elsewhere in this report and in the Partnership’s other filings with the Securities and Exchange Commission could substantially harm our business, results of operations and financial condition and that upon the occurrence of any of these events, the trading price of our common units could decline, and you could lose all or part of your investment.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1A. Risk Factors