What changed in this filing

/stocks — the workspaceLOADING

Item 1A. Risk Factors

2022-02-24 compared with 2021-02-25 · 169 added, 121 removed, 359 unchanged (45% of the section changed)

21 unchanged sentences

Our unitholders are not able to influence or control the operation or future development of the properties underlying the NPIs.

The Operating Partnership is unable to influence significantly the operations or future development of properties that it does not operate.

The Operating Partnership is unable to influence the operations or future development of properties that it does not operate.

The current operators of the properties underlying the NPIs are under no obligation to continue operating the underlying properties.

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This could result in termination of the NPIs relating to the abandoned well.

Cash distributions are affected by production and other costs, some of which are outside of our control.

Cash distributions are affected by production and other costs, most of which are outside of our control.

The cash available for distribution that comes from our royalty and mineral interests, including the NPIs, is directly affected by increases in production costs and other costs.

Some of these costs are outside of our control, including costs of regulatory compliance and severance and other similar taxes.

Most of these costs are outside of our control, including costs of regulatory compliance and severance and other similar taxes.

Other expenditures are dictated by business necessity, such as drilling additional wells in response to the drilling activity of others.

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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.

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.

Leases on oil and natural gas properties typically have a term of three years, after which they expire unless, prior to expiration, production is established within the spacing units covering the undeveloped acres.

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.

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.

If the lease underlying any of our ORRIs expires or terminates, our ORRIs that are derived from such lease will also terminate.

Any such expirations or terminations of our leases or our ORRIs could materially and adversely affect our financial condition, results of operations and cash flow.

If our operators suspend our right to receive royalty payments due to title or other issues, our business, financial condition, results of operations and cash flows may be adversely affected.

Our business depends, in part, on acquisitions which contribute to the growth of our reserves, production and cash generated from operations.

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.

If an operator of our properties is not satisfied with the documentation we provide to validate our ownership, such operator may suspend our royalty payment until such issues are resolved, at which time we would receive the full royalty payment which we would have otherwise received if not for the payment being suspended, without interest.

Certain of our operators impose burdensome documentation requirements for title transfer and may keep royalty payments in suspense for significant periods of time.

During the time that an operator puts our assets in pay suspense, we would not receive the applicable mineral or royalty payment owed to us from sales of the underlying oil or natural gas related to such mineral or royalty interest.

If a significant amount of our royalty interests are placed in suspense, our results of operations and cash flow may be materially affected.

Title to the properties in which we have an interest may be impaired by title defects.

In our discretion, we may elect not to incur the expense of retaining lawyers to examine the title to our royalty and mineral interests.

In such cases, we would rely upon the judgment of oil and gas lease brokers or landmen who perform the fieldwork in examining records in the appropriate governmental office before acquiring a specific royalty or mineral interest.

The existence of a material title deficiency can have a significant adverse effect on the value of an interest and can further materially adversely affect our results of operations, financial condition and cash flows.

We may experience delays in received royalty payments and be unable to replace operators that do not make required royalty payments, and we may not be able to terminate our leases with defaulting lessees if any of the operators on those leases declare bankruptcy.

We may experience delays in receiving royalty payments from our operators, including as a result of delayed division orders received by our operators.

Typically, the failure of an operator to make royalty payments to which we are entitled, gives us the right to terminate the lease, repossess the property and enforce payment obligations under the lease.

If we repossessed any of our properties, we would seek a replacement operator.

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 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.

In addition, if we are able to enter into a new lease with a new operator, there is no guarantee that such replacement operator will achieve the same levels of production or sell oil or natural gas at the same price as the operator it replaced.

We do not currently plan to enter into hedging arrangements with respect to the oil and natural gas production from our properties, and we will be exposed to the impact of decreases in the price of oil and natural gas.

We do not currently plan to enter into hedging arrangements to establish, in advance, a price for the sale of the oil and natural gas produced from our properties.

As a result, although we may realize the benefit of any short-term increase in the price of oil and natural gas, we will not be protected against decreases in the price of oil and natural gas or prolonged periods of low commodity prices, which could materially adversely affect our business, results of operation and cash available for distribution.

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.

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.

Many of these companies explore for and produce oil and natural gas, carry on midstream and refining operations, and market petroleum and other products on a regional, national or worldwide basis.

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.

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.

Such combined companies may compete against our operators or, in the case of consolidation amongst our operators, may choose to focus their operations on areas outside of our properties.

In addition, we cannot guarantee our ability to acquire additional properties and to discover reserves in the future as this will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.

Drilling activities on our properties may not be productive, which could have an adverse effect on future results of operations and financial condition.

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A significant portion of the properties subject to the NPIs are properties located in the Bakken region and Permian Basin.

Because of this geographic concentration, any regional events, including natural disasters that increase costs, reduce availability of equipment or supplies, reduce demand or limit production may impact the net proceeds payable under the NPIs more than if the properties were more geographically diversified.

Because of this geographic concentration, any regional events, including natural disasters that increase costs, reduce availability of equipment, services, or supplies, reduce demand or limit production may impact the net proceeds payable under the NPIs more than if the properties were more geographically diversified.

Under the terms of the NPIs, much of the economic risk of the underlying properties is passed along to us.

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For example, in Oklahoma, where properties that are subject to the NPIs are located, regulators have the ability, directly or indirectly, to limit production from those 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 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 gas industry depends on digital technologies in exploration, development, production, and processing activities.

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.

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.

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It is possible that our business, finances, systems and assets could be compromised in a cyber attack.

The Partnership may be adversely affected by the recent oversupply of oil and natural gas as a result of the actions of Saudi Arabia and Russia.

Recent actions by Saudi Arabia and Russia have caused a worldwide oversupply in oil and natural gas.

After OPEC and a group of oil producing nations led by Russia failed in March 2020 to agree on oil production cuts, Saudi Arabia announced that it would cut oil prices and increase production, leading to a sharp further decline in oil and natural gas prices.

The Partnership may be adversely affected by price volatility in the oil and natural gas markets.

Historically, there has been price volatility in the oil and natural gas markets, which have been impacted by a number of factors, including actions by oil producing nations.

For example, after OPEC and a group of oil producing nations led by Russia failed in March 2020 to agree on oil production cuts, Saudi Arabia announced that it would cut oil prices and increase production, leading to a sharp decline in oil and natural gas prices.

While OPEC, Russia and other oil producing countries reached an agreement in April 2020 to reduce production levels, and U.S.

production has declined, oil prices remain lower than in recent years on account of an oversupply of oil and natural gas, with a simultaneous decrease in demand as a result of the impact of COVID-19 on the global economy, and such significant decrease in the prices of hydrocarbons may have a material adverse effect on our cash distributions.

Oil and natural gas operators on our properties may suspend drilling programs and may lose significant customers as purchasers, which would impact our revenues and operating income.

production declined, oil prices remained lower than in previous years on account of an oversupply of oil and natural gas, with a simultaneous decrease in demand as a result of the impact of COVID-19 on the global economy.

Thereafter, in 2021, oil and natural gas prices significantly rebounded.

Although we continue to see sustained improvements in pricing, on account of a number of factors, including unusually high pricing due to extreme winter weather in early 2021, the oil and natural gas markets remain subject to price volatility, which may have a material adverse effect on our cash distributions in periods of lower prices.

During periods of substantial declines in prices, such as in 2020, oil and natural gas operators on our properties may suspend drilling programs, which would impact our revenues and operating income.

In the event that any wells on our properties are shut-in, restarting wells may require significant costs from our operators, and we cannot guarantee that they would be able to restart at the same level.

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Future environmental law developments, such as stricter laws, regulations or enforcement policies, could significantly increase the costs of production from our properties and reduce our cash flow.

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

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state statutes impose strict liability, 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 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.

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

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.

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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 gas are currently excluded from regulation under RCRA’s hazardous waste provisions.

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

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.

In addition, exploration and production wastes are regulated under state laws analogous to RCRA.

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

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 gas wastes.

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.

1 unchanged sentence

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 use specific equipment or technologies to control emissions.

Environmental Protection Agency (“EPA”) continues to develop stringent regulations governing emissions of toxic air pollutants from oil and gas facilities.

Most recently, EPA published two new rules on September 14 and 15, 2020 that remove the transmission and storage sectors of the oil and gas industry from regulation under the New Source Performance Standards (“NSPS”) and rescind methane-specific standards for the production and processing segments of the industry.

However, states and environmental groups brought suit challenging the new rules almost immediately.

Although the bulk of the 2012 and 2016 standards are currently in effect, future implementation and the ultimate scope of the 2012 and 2016 standards are uncertain at this time as a result of these challenges and current uncertainty regarding how the standards may be altered under the administration of recently elected U.S.

President Biden.

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.

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.

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.

In November 2016, the Bureau of Land Management (“BLM”) published a final version of its venting and flaring rule, which imposes stricter reporting obligations and limits venting and flaring of natural gas on federal and Indian lands.

Some provisions of the venting and flaring rule went into effect on January 17, 2017.

The BLM subsequently announced that it was postponing until January 17, 2019, the implementation of other aspects of the venting and flaring rule, which were originally scheduled to come into effect on January 1, 2018.

Then, in February 2018, the BLM issued a proposed rule which would rescind, modify, and retain portions of the November 2016 rule.

And in September 2018, the BLM announced a final rule that revises the 2016 rule, which was immediately followed by litigation challenging the agency’s actions.

Most recently, in October 2020, a ruling by the U.S.

District Court for the District of Wyoming resulted in vacatur of the 2016 venting and flaring rule with the exception of certain royalty provisions.

In March 2015, the BLM released its new regulations governing hydraulic fracturing operations on federal and Indian lands, including requirements for chemical disclosure, well bore integrity and handling of flowback water.

District Court of Wyoming temporarily stayed implementation of this rule in June 2016, but the U.S.

Court of Appeals for the Tenth Circuit later lifted the lower court’s stay on the basis that the BLM had proposed to rescind the rule in June 2017.

In December 2017, the BLM published a final rule rescinding the March 2015 rule.

BLM’s repeal of the rule was challenged in court, and in April 2020, the Northern District of California issued a ruling in favor of the BLM.

Each of these regulations, to the extent that they are reinstated or modified, may result in additional levels of regulation or complexity that could lead to operational delays, increased operating costs and additional regulatory burdens that could make it more difficult to perform hydraulic fracturing and increase costs of compliance.

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

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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”).

In May 2015, EPA and the USACOE jointly announced a final rule defining the “Waters of the United States”

(“WOTUS”), that are protected under the Clean Water Act.

However, the rule, which would have made additional waters expressly WOTUS and, therefore, subject to the jurisdiction of the Clean Water Act, rather than subject to a case-specific evaluation and EPA’s subsequent rulemaking actions to delay implementation and repeal the rule has been heavily litigated since.

In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became effective in December 2019, reinstating the pre 2015 standards.

Litigation of the repeal quickly ensued.

Meanwhile, in December 2018, the EPA and the Corps issued a proposed rule to revise the definition of “WOTUS.”

The rule was finalized in January 2020, and became effective in June 2020.

The rule narrows the WOTUS definition, excluding, for example, streams that flow only after precipitation and wetlands without a direct surface connection to traditional navigable waters.

Litigation by parties opposing the rule again quickly followed, including a challenge in the U.S.

District Court for the District of Colorado, which resulted in a statewide stay of the rule on June 19, 2020.

This ruling is currently being appealed in the Tenth Circuit.

Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of Royalty Properties, and changes to the WOTUS definition could cause delays in development and/or increase the cost of development and operation of those properties.

On June 29, 2015, 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 December 7, 2021, the EPA and the Corps published a proposed rule that would put back into place the pre-2015 definition of “waters of the United States,”

updated to reflect Supreme Court decisions, while the agencies continue to consult with stakeholders on future regulatory actions.

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 Clean Water Act 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.

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Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

The Safe Drinking Water Act (“SDWA”) and the Underground Injection Control (“UIC”) program require that permits be obtained before drilling salt water disposal wells, and casing integrity monitoring be conducted periodically to ensure that the disposed waters are not leaking into groundwater.

In addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to seismic activity, they have adopted or are considering additional regulations regarding such disposal methods.

Changes in regulations or the inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Royalty Properties and the operators of the working interests and other properties underlying our NPIs to dispose of produced water and ultimately increase the cost of operation of the Royalty Properties and the working interests and other properties underlying our NPIs or delay production schedules.

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.

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.

More recently, the OCC directed the shut in of a number of disposal wells due to increased earthquake activity in the Arbuckle formation and imposed further disposal well volume reductions in the Covington, Crescent, Enid, and Edmond areas.

Moreover, vigorous public debate over hydraulic fracturing and shale gas production continues, and has resulted in delays of well permits in some areas.

In addition, several cases have recently put a spotlight on the issue of whether injection wells may be regulated under the Clean Water Act if a direct hydrological connection to a jurisdictional surface water can be established.

The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019.

EPA has also brought attention to the reach of the Clean Water Act’s jurisdiction in such instances.

EPA issued a request for comment in February 2018 regarding the applicability of the Clean Water Act permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered “direct,”

and whether such discharges would be better addressed through other federal or state programs, but concluded in April 2019 that the Clean Water Act should not be interpreted to require permits for discharges of pollutants that reach surface waters via groundwater.

However, in April 2020, the Supreme Court issued a ruling in the case County of Maui, Hawaii v.

Hawaii Wildlife Fund, holding that discharges into groundwater may be regulated under the CWA if the discharge is the “functional equivalent”

of a direct discharge into navigable waters.

On December 10, 2020, EPA issued a draft guidance on the ruling, which emphasized that discharges to groundwater are not necessarily the “functional equivalent”

of a direct discharge based solely on proximity to jurisdictional waters.

If in the future CWA permitting is required for any saltwater injection wells as a result of the Supreme Court’s ruling in County of Maui, Hawaii v.

Hawaii Wildlife Fund, the costs of permitting and compliance for any injection well operations could increase.

Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources.

These statutes include the Endangered Species Act, the Migratory Bird Treaty Act, the CWA, and CERCLA.

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 gas exploration or production).

Where takings of, or harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages and, in some cases, criminal penalties.

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

The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges.

In addition, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities.

Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

Various federal laws, including the Endangered Species Act and the Migratory Bird Treaty Act, and analogous state laws, restrict activities that may adversely affect listed endangered or threatened species or their habitat.

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.

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 potential adoption of federal and state hydraulic fracturing legislation or executive orders could delay or restrict development of our oil and natural gas properties.

The Energy Policy Act of 2005 exempts hydraulic fracturing from federal regulation under the SDWA, provided that diesel fuel is not used in the fracturing process.

In addition, in February 2014, the EPA published final guidance that broadly defined diesel fuel and which requires the issuance of a Class II Underground Injection Control permit for hydraulic fracturing treatments using diesel fuel.

These requirements may cause additional costs and delays in the hydraulic fracturing process using diesel fuel.

Further, in each session of Congress since 2009, legislation has been introduced that would have repealed the hydraulic fracturing exemption.

If similar legislation were enacted, it 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 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.

Hydraulic fracturing is an important, common practice that is used to stimulate production of hydrocarbons from tight formations, including shales.

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.

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.

Also, on November 18, 2016, the BLM finalized a rule to reduce the flaring, venting and leaking of methane from oil and natural gas operations on federal and Indian lands.

On March 28, 2017, former President Trump signed an executive order directing the BLM to review the above rules and, if appropriate, to initiate a rulemaking to rescind or revise them.

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.

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

however, a federal court struck down the scaled-back rule on July 15, 2020, and shortly thereafter, on October 8, 2020, another federal court struck down the 2016 methane rule.

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

Additionally, certain states in which our properties are located, including Oklahoma, Texas and Wyoming, have adopted, and other states are considering adopting, regulations that could impose more stringent permitting, public disclosure and well construction requirements on hydraulic-fracturing operations or otherwise seek to ban fracturing activities altogether.

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In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit well drilling in general and/or hydraulic fracturing in particular.

In response to a 2014 ballot initiative by the voters of the City of Denton, Texas banning hydraulic fracturing, the Texas legislature enacted a statute preempting local government regulation of oil and gas activities, including hydraulic fracturing.

In other states, however, local governments may retain the ability to directly or indirectly regulate hydraulic fracturing.

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In the event state, local, or municipal legal restrictions are adopted in areas where our properties are located, the cost of the operators of our oil and natural gas properties to comply with such requirements may be significant in nature, which may cause delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even preclude the operators from drilling wells.

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

Congress has, from time to time, considered legislation to reduce greenhouse gas (“GHG”) emissions, such as a resolution referred to as the Green New Deal, which was introduced in the U.S.

House of Representatives in February 2019.

Some states have become concerned about the connection between hydraulic fracturing-related activities, particularly the injection or disposal of produced water, and the increased occurrence of seismic activity, and they have adopted or are considering additional regulations regarding such activities.

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.

The Texas Railroad Commission has also implemented measures to assess the potential for seismic activity in the vicinity of disposal wells, and it has restricted and indefinitely suspended disposal well activities in some cases.

Moreover, vigorous public debate over hydraulic fracturing and shale gas production continues and has resulted in delays of well permits in some areas.

Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices.

On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources.

Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells.

The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events.

Other governmental agencies have also evaluated or are evaluating various other aspects of hydraulic fracturing.

These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for our operators to perform fracturing and increase their costs of compliance and doing business.

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.

Congress has, from time to time, considered legislation to reduce greenhouse gas (“GHG”) emissions, such as the Build Back Better Act approved by the U.S.

House of Representatives in November 2021.

To date, Congress has not passed a bill specifically addressing GHG regulation.

Almost half of the states, however, have developed GHG emission inventories and/or regional GHG cap and trade programs.

These cap and trade programs require major sources of emissions or major fuel producers to acquire and surrender emission allowances corresponding with their annual emissions of GHGs.

Almost half of the states, however, have taken measures to reduce GHG emissions primarily though the development of GHG emission inventories and/or regional GHG cap and trade programs.

The cap and trade programs require major sources of emissions or major fuel producers to acquire and surrender emission allowances corresponding with their annual emissions of GHGs.

The number of allowances available for purchase is reduced each year until the overall GHG emission reduction goal is achieved.

Many states also have enacted renewable portfolio standards, which require utilities to purchase a certain percentage of their energy from renewable fuel sources.

Responding to scientific studies that have suggested that emissions of gases, commonly referred to as “greenhouse gases,”

including gases associated with the oil and gas sector such as carbon dioxide, methane, and nitrous oxide among others, may be contributing to global warming and other environmental effects, the EPA has begun to adopt regulations to report and reduce emissions of greenhouse gases.

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

Responding to scientific studies that have suggested that emissions of GHGs, including gases associated with the oil and natural gas sector such as carbon dioxide, methane, and nitrous oxide among others, may be contributing to global warming and other environmental effects, the EPA has begun to adopt regulations to report and reduce emissions of greenhouse gases.

Any such regulations may have the potential to affect our business, customers or the energy sector generally.

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 in 2016, with the objective of limiting greenhouse gas emissions.

Although the U.S.

took steps to withdraw from the Paris Agreement during President Trump’s administration, the earliest date of withdrawal under the terms of the agreement was November 4, 2020, one day after the 2020 U.S.

Presidential election.

President Biden issued an Executive Order on January 20, 2021 committing to rejoin the Paris Agreement.

Although the Paris Agreement does not include obligations that are directly binding on companies, additional GHG reduction regulatory requirements may be issued in an effort to help meet the U.S.

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 in 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.

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.

commitments under the Paris Agreement.

Although it is not possible at this time to predict whether or when Congress may act on climate change legislation, or whether EPA may promulgate additional regulation of GHGs from the oil and gas industry, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require oil and gas operators that develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas produced from the Royalty Properties.

Finally, it should be noted that, recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.

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

Although it is not possible at this time to predict whether or when Congress may act on climate change legislation, or whether EPA may promulgate additional regulation of GHGs from the oil and natural gas industry, any laws or regulations that may be adopted to restrict or reduce emissions of GHGs could require oil and natural gas operators that develop our properties to incur increased operating costs and could have an adverse effect on demand for the oil and natural gas produced from our properties.

It should also be noted that, recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities.

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.

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

Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and natural gas will continue to represent a substantial percentage of global energy use over that time.

Finally, climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels.

Another possible consequence of climate change is increased volatility in seasonal temperatures.

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.

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.

The new Biden administration,  

acting through the executive branch or in coordination with Congress, could enact rules and regulations that reduce our revenues and cash distributions in the future or increase operating costs for the oil and natural gas production from our properties.

During the campaign, President Biden stated that, if elected President, he would issue Executive Orders to permanently protect certain federal lands, establish monuments, restrict new oil and gas permitting on public lands and waters, and modify royalties to account for climate costs.

In January 2021, President Biden signed an Executive Order temporarily suspending oil and gas permitting on federal lands and waters for 60 days.

In addition, President Biden has indicated that his administration is likely to pursue more stringent methane pollution limits for new and existing oil and gas operations.

These efforts, among others, are intended to support Mr.

Biden’s stated goal of addressing climate change.

Potential actions of a Democratic-controlled Congress include imposing more restrictive laws and regulations pertaining to permitting, limitations on greenhouse gas emissions, increased requirements for financial assurance and bonding for decommissioning liabilities, and carbon taxes.

Any of these administrative or Congressional actions could adversely affect our revenues and cash distributions by requiring oil and gas operators that develop our properties to incur increased operating costs and could have an adverse effect on the amount of and demand for the oil and natural gas produced from our properties.

President Biden has indicated that he is supportive of various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and decarbonize electric generation and the transportation sector.

During his first month in office, in January 2021, President Biden signed an Executive Order temporarily suspending oil and natural gas permitting on federal lands and offshore waters.

While the moratorium was lifted in June 2021, President Biden has indicated that his administration is likely to pursue additional measures to limit GHG emissions from oil and natural gas operations.

It remains unclear, however, what specific actions President Biden will take and what support he will have for any potential legislative changes from Congress.

Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our business or operations.

However, any of these actions could adversely affect our revenues and cash distributions by requiring oil and natural gas operators that develop our properties to incur increased operating costs and could have an adverse effect on the amount of and demand for the oil and natural gas produced from our properties.

Our oil and natural gas reserve data and future net revenue estimates are uncertain.

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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 United States Army Corps of Engineers (the “Army Corps”) to permit the Dakota Access Pipeline, on July 6, 2020, the United States Court for the District of Columbia (the “Court”) issued an order vacating the Army Corps’

easement for the Dakota Access Pipeline and requiring that the pipeline be shut down by August 5, 2020.

Dakota Access, LLC and the Army Corps appealed the decision and filed a motion for a stay pending appeal with the United States Court of Appeals for the District of Columbia Circuit (the “Court of Appeals”).

On July 14, 2020, the Court of Appeals granted a temporary administrative stay to allow the Court time to consider briefing on whether to continue the stay until the appeal is decided on the merits.

On January 26, 2021, the Court of Appeals affirmed that part of the lower court decision vacating the Army Corps’

easement while it prepares a new environmental impact statement, but reversed the lower court’s order to shut down the pipeline because the lower court had not properly evaluated such a move under the applicable test under case law.

As stated by the Court of Appeals, the Army Corps is within its authority to shut down the pipeline and the Court of Appeals would expect the Army Corps to make that decision “promptly.”

On February 9, 2021, the Army Corps, through the Department of Justice, sought a delay of the proceedings to give lawyers time to brief the new presidential administration on the background of the Dakota Access Pipeline matter.

Accordingly, the continued operation of Dakota Access Pipeline in the future is uncertain, and an Executive Order by President Biden could significantly impact the Dakota Access Pipeline.

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 late 2022.

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

While this litigation does not directly impact our operations, we derive a significant amount of revenue from the Royalty Properties and NPIs we hold in the Bakken region, the region for which the Dakota Access Pipeline is intended to be a key pipeline.

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Public health threats and other highly communicable diseases, outbreaks of which have been occurring in across the world, including the United States, could adversely impact our Partnership, drilling activities on our properties and the global economy.

In particular, the outbreak starting in 2020 of a novel coronavirus (COVID-19) has resulted in quarantines, restrictions on travel and a decrease in economic activity across the world, which has resulted in a decrease in demand for hydrocarbons.

The COVID-19 pandemic may continue to have a material adverse effect on the demand for hydrocarbons and the prices at which they are sold, which may impact our revenues and operating income, our cash distributions and our business generally.

It is impossible to predict the effect of the continued spread, or fear of continued spread, of COVID-19 globally.

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

In particular, the outbreak starting in 2020 of a coronavirus (COVID-19) has resulted in quarantines, restrictions on travel and a decrease in economic activity across the world, which has resulted in a decrease in demand for hydrocarbons.

The COVID-19 pandemic and its ongoing variants may continue to have a material adverse effect on the demand for hydrocarbons and the prices at which they are sold, which may impact our revenues and operating income, our cash distributions and our business generally.

It is impossible to predict the effect of the continued spread, or fear of continued spread, of COVID-19 and its ongoing variants globally.

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.

Disclosure Regarding Forward-Looking Statements

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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, including the recent significant decline in energy prices, public health crises including the worldwide coronavirus (COVID-19) outbreak beginning in early 2020, 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, 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.

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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