What changed in this filing

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Item 1A. Risk Factors

2023-02-23 compared with 2022-02-24 · 59 added, 39 removed, 489 unchanged (17% of the section changed)

152 unchanged sentences

These laws and regulations can have a significant impact on production and costs of production.

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.

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.

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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.

Although we continue to see sustained improvements in pricing, on account of a number of factors, 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.

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Moreover, due to the extremely volatile market conditions, we are unable to predict the degree or duration of any adverse impact on our operations and financial condition and other risks in our industry may be enhanced by such conditions.

Continuing or worsening inflationary issues and associated changes in federal monetary policy may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise and may delay or restrict their exploration and development activities.

The rate of inflation in the U.S.

has been steadily increasing since 2021 and through 2022.

These inflationary pressures may result in increases to the costs of the goods, services and labor used by our operators, which could cause their capital expenditures and operating costs to rise.

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’

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.

Regulatory and Environmental Risk Factors

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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.

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.

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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”).

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

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 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.

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 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.

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.

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.

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.

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

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These laws also require the development of risk management plans for certain facilities to prevent accidental releases of extremely hazardous substances and to minimize the consequences of such releases should they occur.

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

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

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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.

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.

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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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 taken measures to reduce GHG emissions primarily though the development of GHG emission inventories and/or regional GHG cap and trade programs.

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

Specifically, the IRA amends the Clean Air Act to impose a fee on the emission of methane that exceeds an applicable waste emissions threshold from sources required to report their GHG emissions to the EPA, including sources in the offshore and onshore petroleum and natural gas production and gathering and boosting source categories.

The methane emissions charge would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 in 2025 and be set at $1,500 for 2026 and each year after.

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.

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.

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.

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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.

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”).

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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.

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.

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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 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.

Although it is not possible at this time to predict whether or when Congress may adopt additional 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.

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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.

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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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.

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.

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.

The outcome of this litigation may have a material adverse affect on our Royalty and NPI revenues derived from the Bakken region based on the timing of future development of wells on, or production of oil and natural gas from, or the method and cost of transportation related to the production on the properties.

The outcome of this litigation may have a material adverse effect on our Royalty and NPI revenues derived from the Bakken region based on the timing of future development of wells on, or production of oil and natural gas from, or the method and cost of transportation related to the production on the properties.

We have no control over the operation of such properties.

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Net income as reported for financial statement purposes is presented on an accrual basis in conformity with accounting principles generally accepted in the United States of America.

Unitholder K-1 tax statements are calculated based on applicable tax conventions, and taxable income as calculated for each year will be allocated among unitholders who hold units on the last day of each month.

Unitholder Schedule K-1 tax statements are calculated based on applicable tax conventions, and taxable income as calculated for each year will be allocated among unitholders who hold units on the last day of each month.

Distributions, however, are calculated on the basis of actual cash receipts, changes in cash reserves, and disbursements during the relevant reporting period.

Consequently, due to timing differences between the receipt of proceeds of production and the point in time at which the production giving rise to those proceeds actually occurs, net income reported on our consolidated financial statements and on unitholder K-1's will not reflect actual cash distributions during that reporting period.

Consequently, due to timing differences between the receipt of proceeds of production and the point in time at which the production giving rise to those proceeds actually occurs, net income reported on our consolidated financial statements and on unitholder Schedule K-1 tax statements will not reflect actual cash distributions during that reporting period.

Our unitholders have limited voting rights and do not control our General Partner, and their ability to remove our General Partner is limited.

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We are dependent upon key personnel, and the loss of services of any of our key personnel could adversely affect our operations.

Our continued success depends to a considerable extent upon the abilities and efforts of the senior management of our General Partner, particularly William Casey McManemin, its Chief Executive Officer, Bradley J.

Ehrman, its Chief Operating Officer and Leslie A.

Moriyama, its Chief Financial Officer.

Ehrman, and Chief Financial Officer, Leslie A.

The loss of the services of any of these key personnel could have a material adverse effect on the results of our operations.

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However, it is possible that we may realize income that would constitute UBTI in an effort to maximize unitholder value.

Our unitholders may be subject to withholding tax upon transfers of their common units.

If a unitholder sells or otherwise disposes of a common unit, the transferee generally is required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from distributions to the transferee amounts that should have been withheld by the transferee but were not withheld.

Final regulations issued on October 7, 2020, provide rules for withholding on the transfer of a partnership interest in a publicly traded partnership.

However, the Treasury Department and the IRS have suspended these rules for transfers of certain publicly traded partnership interests, including transfers of our common units, that occur before January 1, 2023.

For transfers of our common units occurring on or after January 1, 2023, withholding will be required on open market transactions, but in the case of a transfer made through a broker, a partner’s share of liabilities will be excluded from the amount realized.

In addition, the obligation to withhold will be imposed on the broker instead of the transferee (and we will generally not be required to withhold from the transferee amounts that should have been withheld by the transferee but were not withheld).

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

Tax consequences of certain NPIs are uncertain.

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If we are required to make payments of taxes, penalties and interest resulting from audit adjustments, our cash available for distribution to our unitholders might be substantially reduced.

Our unitholders may be subject to withholding tax upon transfers of their common units.

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.

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.

General Risk Factors

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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 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.

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

At its height, the COVID-19 pandemic had a significant negative effect on the global economy, supply chains and labor force participation, and created significant volatility in financial markets.

Although the effects of the pandemic during 2022 were not as significant as prior years, new variants continued to cause waves of COVID-19 cases around the world.

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.

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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.

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.

As a public company, we have incurred and will continue to incur significant legal, accounting and other expenses, particularly since we are now a large accelerated filer and are no longer a smaller reporting company.

The Sarbanes-Oxley Act of 2002, or the Sarbanes Oxley Act, the Dodd-Frank Wall Street Reform and Consumer Protection Act, the listing requirements of the Nasdaq Global Select Market and other applicable securities rules and regulations impose various requirements on public companies.

Our management and other personnel will need to continue to devote a substantial amount of time to comply with these requirements.

Moreover, these rules and regulations have increased, and will continue to increase, our legal and financial compliance costs and will make some activities more time-consuming and costly.

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.

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.

This could result in future uncertainty regarding compliance matters and higher costs necessitated by ongoing revisions to disclosure and governance practices.

Disclosure Regarding Forward-Looking Statements

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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