What changed in this filing

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Item 1A. Risk Factors

2022-02-22 compared with 2021-02-23 · 107 added, 89 removed, 544 unchanged (26% of the section changed)

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In that case, we might not be able to make distributions on our common units, the trading price of our common units could decline, and holders of our units could lose all or part of their investment.

The COVID-19 pandemic and the significant decline in commodity prices in 2020 has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.

The COVID-19 pandemic and the effect on our financial condition, results of operations, and cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.

The COVID-19 pandemic has adversely affected the global economy, disrupted global supply chains and created significant volatility in the financial markets.

In addition, the pandemic has resulted in travel restrictions, business closures and the institution of quarantining and other restrictions on movement in many communities.

As a result, there has been a significant reduction in demand for and prices of oil, natural gas and NGLs.

In the first quarter of 2020 and into the second quarter of 2020, oil prices fell sharply and dramatically, due in part to significantly decreased demand as a result of the COVID-19 pandemic and the announcement by Saudi Arabia of a significant increase in its maximum oil production capacity as well as the announcement by Russia that previously agreed upon oil production cuts between members of the Organization of the Petroleum Exporting Countries and its broader partners (“OPEC+”) would expire on April 1, 2020, and the ensuing expiration thereof.

Agreed-upon production cuts by OPEC+ along with declining U.S.

production have helped to correct the supply and demand imbalance;

however, these reductions are not expected to be enough in the near-term to offset the significant inventory build caused by demand destruction from the COVID-19 pandemic in 2020.

Prices for oil were over $60 per barrel at the beginning of 2020 before declining significantly through March and further declining into April.

While oil prices have recovered, a reversal of recent improvements or a prolonged period at current prices may materially and adversely affect our financial condition, results of operations, and cash distributions to unitholders.

With widespread availability of vaccines, the U.S.

Centers for Disease Control and Prevention has revised its guidance, travel restrictions have started to lift, and businesses have reopened.

However, the COVID-19 pandemic continues to evolve and the extent to which our operating and financial results will continue to be affected will depend on various factors beyond our control, such as the duration, severity, and sustained geographic resurgence of the virus;

the emergence of new variants;

and the success of actions to contain the virus and its variants, or treat its impact.

The impact of the COVID-19 pandemic has negatively affected the oil and natural gas business environment, primarily by causing a reduction in commercial activity and travel worldwide thereby lowering energy demand.

This, in turn, has resulted in significantly lower market prices for oil, natural gas, and NGLs.

This, in turn, resulted in

periods of significantly lower market prices for oil, natural gas, and natural gas liquids.

While we use derivative instruments to partially mitigate the impact of commodity price volatility, our revenues and operating results depend significantly upon the prevailing prices for oil and natural gas.

The current price environment has caused many of our operators to reduce their drilling and completion activity on our acreage, and caused some of our operators to temporarily shut-in production from existing wells, both of which negatively impact our production volumes.

While we believe most of the shut-in production has been brought back on-line, drilling and completion activity remains depressed relative to pre-pandemic levels.

The current price environment also caused us to determine that certain depletable units consisting of mature oil producing properties were impaired.

Therefore, we recognized impairment of oil and natural gas properties of $51.0 million for the year ended December 31, 2020.

Additionally, the borrowing base under the Credit Facility, which takes into consideration the estimated loan value of our oil and natural gas properties, was reduced from $650.0 million to $460.0 million, effective May 1, 2020.

Effective July 21, 2020, in connection with the closing of our two asset sales in the Permian Basin, the borrowing base was further reduced to $430.0 million.

Effective November 3, 2020, the most recent borrowing base redetermination reduced the borrowing base to $400.0 million.

Commodity prices improved in late 2020 and fully recovered in 2021, causing many of our operators to resume their drilling and completion activity on our acreage.

However, the current business environment remains uncertain and a reversal of these improvements may materially and adversely affect our financial condition, results of operations, and cash distributions to unitholders.

The price environment in 2020 resulting from the COVID-19 pandemic, including the sharp decline in oil prices that began in March 2020, caused us to determine that certain depletable units consisting of mature oil producing properties were impaired as of March 31, 2020.

Therefore, we recognized impairment of oil and natural gas properties of $51.0 million in the first quarter of 2020.

Additionally, the borrowing base under the Credit Facility (as defined below) takes into consideration the estimated loan value of our oil and natural gas properties.

Effective November 3, 2020, the borrowing base redetermination reduced the borrowing base from $430.0 million to $400.0 million.

The April and October 2021 borrowing base redeterminations reaffirmed the borrowing base at $400.0 million.

The next borrowing base redetermination is scheduled for April 2022.

In a prolonged period of low commodity prices, we may be required to impair additional properties and the borrowing base under our Credit Facility could be further reduced.

In light of the challenging business environment and uncertainty caused by the pandemic, the Board also approved a reduction in the quarterly distribution for the first quarter of 2020 to increase the amount of retained free cash flow for debt reduction and balance sheet protection.

The Board approved increases to the quarterly distribution for the second and fourth quarters of 2020, but the distribution remains below 2019 levels.

We enter into derivative instruments to partially mitigate the impact of commodity price volatility on our cash generated from operations.

Any declines in production or production forecasts as a result of low commodity prices in light of the COVID-19 pandemic and global oversupply could limit our ability to hedge future volumes.

To protect the health and well-being of our workforce in the wake of COVID-19, we have implemented remote work arrangements for all employees.

Any declines in production or production forecasts in light of the COVID-19 pandemic could limit our ability to hedge future volumes.

To protect the health and well-being of our workforce in the wake of COVID-19, we have maintained remote work arrangements for all employees.

To the extent circumstances require us to maintain remote work arrangements indefinitely, our operational efficiency could be adversely affected, which could in turn adversely affect our financial condition and results of operations.

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The table below demonstrates such volatility for the periods presented.

Year Ended December 31, 2020 During the Five Years Prior to 2021 As of December 31,

Year Ended December 31, 2021

During the Five Years Prior to 2021 As of December 31,

2021 2020 2019

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23.86 2.43 6.24 1.33 3.82 2.36 2.09

2 High price for Henry Hub was due to temporary supply and demand imbalances caused by the February 2021 winter storm.

3 High prices for WTI and Henry Hub were in 2018.

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Specifically, they may abandon any well if they reasonably believe that the well can no longer produce oil or natural gas in commercially paying quantities.

Based on the EIA forecasts for 2021 and 2022, oil prices are expected to trade in a lower range compared to recent historical highs.

Approximately 48% of our 2021 oil and natural gas revenues were derived from oil and condensate sales.

Any additional decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay quarterly distributions on our common units, perhaps materially.

The spot WTI market price at Cushing, Oklahoma has declined from $98.17 per Bbl on December 31, 2013 to $48.35 per Bbl on December 31, 2020.

The reduction in price has been caused by many factors, including substantial increases in U.S.

oil production from unconventional (shale) reservoirs, with limited increases in demand.

Any future decreases in prices of oil may adversely affect our cash generated from operations, results of operations, financial position, and our ability to pay quarterly distributions on our common units, perhaps materially.

During the ten years prior to December 31, 2021, WTI market prices at Cushing, Oklahoma have ranged from a high of $110.62 per Bbl in 2013 to a low of $8.91 per Bbl in 2020.

On December 31, 2021, the WTI spot market price of oil was $75.33.

The changes in the price of oil have been caused by many factors, including periods of increasing U.S.

oil production from unconventional (shale) reserves, periods of investment restraint from U.S.

oil and natural gas producers, actions taken by members of the Organization of the Petroleum Exporting Countries and its broader partners ("OPEC+"), and recent fluctuations in demand as a result of the COVID-19 pandemic.

If prices for oil are depressed for an extended period of time or there are future declines, we may be required to write down the value of our oil and natural gas properties in addition to impairments taken during 2015, 2016, and 2020, and some of our undeveloped locations may no longer be economically viable.

In addition, sustained low prices for oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our Credit Facility (defined below) and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service

our indebtedness.

See "—Covid-19— The COVID-19 pandemic and the significant decline in commodity prices in 2020 has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.”

Based on the EIA forecasts for 2021 and 2022, natural gas prices are expected to trade in a range lower than historical highs.

In addition, sustained low prices for oil may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our Credit Facility and reduce the amounts of cash we would otherwise have available to pay expenses, fund capital expenditures, make distributions to our unitholders, and service our indebtedness.

See "—Covid-19— The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of

operations, and cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.”

Approximately 52% of our 2021 oil and natural gas revenues were derived from natural gas and natural gas liquids sales.

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On December 31, 2021, the Henry Hub spot market price of natural gas was $3.82 per MMBtu.

The reduction in prices has been caused by many factors, including increases in natural gas production from unconventional (shale) reservoirs, without an offsetting increase in demand.

The expected increase in natural gas production in 2020, based on reports from the EIA, could cause the prices for natural gas to remain at current levels or fall to lower levels.

The changes in the price of natural gas have been caused by many factors, including periods of increasing U.S.

natural gas production from unconventional (shale) reserves, periods of investment restraint from U.S.

oil and natural gas producers, seasonal changes in demand for heating by residential and commercial customers, rising levels of U.S.

natural gas exports, and recent fluctuations in demand as a result of the COVID-19 pandemic.

If prices for natural gas are depressed for an extended period of time or there are future declines, we may be required to further write down the value of our oil and natural gas properties in addition to impairments taken during 2015, 2016, and 2020, and some of our undeveloped locations may no longer be economically viable.

In addition, sustained low prices for natural gas may negatively impact the value of our estimated proved reserves and the amount that we are allowed to borrow under our Credit Facility and reduce the amounts of cash we would otherwise have available to pay expenses, make distributions to our unitholders, and service our indebtedness.

See "—Covid-19— The COVID-19 pandemic has adversely affected our business, and the ultimate effect on our financial condition, results of operations, and cash distributions to unitholders will depend on future developments, which are highly uncertain and cannot be predicted.”

Our failure to successfully identify, complete, and integrate acquisitions could adversely affect our growth, results of operations, and cash distributions to unitholders.

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No assurance can be given that we will be able to identify suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms, or successfully acquire identified targets.

Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.

Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully, or to minimize

any unforeseen operational difficulties could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.

The inability to effectively manage the integration of acquisitions could reduce our focus on subsequent acquisitions and current operations, which, in turn, could negatively impact our growth, results of operations, and cash distributions to unitholders.

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Decreases in the available borrowing amount could result from declines in oil and natural gas prices, operating difficulties or increased costs, decreases in reserves, lending requirements, or regulations or certain other circumstances.

As of December 31, 2020, we had

outstanding borrowings of $121.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion.

Our borrowing base determined by the lenders under our Credit Facility in November 2020 is $400.0 million and the next semi-annual redetermination is scheduled for April 2021.

A future decrease in our borrowing base could be substantial and could be to a level below our then-outstanding borrowings.

As of December 31, 2021, we had outstanding borrowings of $89.0 million and the aggregate maximum credit amounts of the lenders were $1.0 billion.

Our borrowing base determined by the lenders under our Credit Facility in October 2021 is $400.0 million and the next semi-annual redetermination is scheduled for April 2022.

A future decrease in our borrowing base could be substantial and could be to a

level below our then-outstanding borrowings.

Outstanding borrowings in excess of the borrowing base are required to be repaid in five equal monthly payments, or we are required to pledge other oil and natural gas properties as additional collateral, within 30 days following notice from the administrative agent of the new or adjusted borrowing base.

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In addition, our obligations under our Credit Facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our Credit Facility, the lenders can seek to foreclose on our assets.

On July 27, 2017, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks to submit LIBOR rates after 2021.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary during its term, which require that we and our lenders agree upon a replacement rate based on the then-prevailing market convention for similar agreements.

On March 5, 2021, the U.K.

Financial Conduct Authority announced that it intends to stop persuading or compelling banks

to submit LIBOR rates after December 31, 2021 for the 1-week and 2-month U.S.

dollar settings and after June 30, 2023 for the

remaining U.S.

dollar settings.

Our Credit Facility includes provisions to determine a replacement rate for LIBOR if necessary

during its term, based on the secured overnight financing rate published by the Federal Reserve Bank of New York (“SOFR”).

We currently do not expect the transition from LIBOR to have a material impact on us.

However, if clear market standards and replacement methodologies have not developed as of the time LIBOR becomes unavailable, we may have difficulty reaching agreement on acceptable replacement rates under our Credit Facility.

In the event that we do not reach agreement on an acceptable replacement rate for LIBOR, outstanding borrowings under the Credit Facility would revert to a floating rate equal to the alternative base rate (which, as of the time that LIBOR becomes unavailable, is equal to the greater of the Prime Rate and the Federal Funds effective rate plus 0.50%) plus the applicable margin for the alternative base rate which ranges between 1.00% and 2.00%.

If we are unable to negotiate replacement rates on favorable terms, it could have a material adverse effect on our financial condition, results of operations, and cash distributions to unitholders.

Please read “Part II, Item 7.

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We expect to distribute a substantial majority of the cash we generate from operations each quarter.

As a result, we will have limited cash generated from operations to reinvest in our business or to fund acquisitions, and we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our

acquisitions and growth capital expenditures.

If we are unable to finance growth externally, our distribution policy will significantly impair our ability to grow.

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Other than limitations restricting our ability to issue units ranking senior or on parity with our Series B cumulative convertible preferred units, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units with respect to distributions.

The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may reduce the cash that we have available to distribute to our unitholders.

The incurrence of additional commercial borrowings or other debt to finance our growth would result in increased interest expense and required principal repayments, which, in turn, may

reduce the cash that we have available to distribute to our unitholders.

Please read Part II, Item 5.

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The amount of oil that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage, or lack of available capacity on these systems, tanker truck availability, and extreme weather conditions.

Also, the shipment of our or our operators’ oil and natural gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners.

Also, the shipment of our or our operators’ oil and natural

gas on third-party pipelines may be curtailed or delayed if it does not meet the quality specifications of the pipeline owners.

The curtailments arising from these and similar circumstances may last from a few days to several months.

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Ultimately, the success of these drilling and completion techniques can only be evaluated over time as more wells are drilled and production profiles are established over a sufficiently long time period.

If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in

these areas may be lower than we anticipate.

If our operators’ drilling results are weaker than anticipated or they are unable to execute their drilling program on our properties, our operating and financial results in these areas may be lower than we anticipate.

Further, as a result of any of these developments we could incur material write-downs of our oil and natural gas properties and the value of our undeveloped acreage could decline, and our results of operations and cash distributions to unitholders could be adversely affected.

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Cessation or protracted slowdown of activity in the Shelby Trough area could adversely affect our results of operations.

In 2020, we generated 13% of our royalty revenues and 54% of our working interest revenues from two operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position.

These operators have recently decided to limit their Shelby Trough drilling activity, and one of the operators has released acreage in the area.

In 2021, we generated 16% of our royalty revenues and 40% of our working interest revenues from three operators in the Shelby Trough area of the Haynesville play in East Texas, where we own a concentrated, relatively high-interest royalty position.

Only one of these operators has an active drilling program on this acreage.

Geographic and operator concentration heightens the effect of operational risks, including:

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• delay or cancellation of construction or operation of LNG export facilities in the Gulf of Mexico.

If drilling activity in this area does not resume at the previous rate, production may decrease, reducing cash generated from operations and, without offsetting cost reductions, cash available for distribution.

If any of these risks are realized and production is not replaced by another operator in this area or another area, production may decrease, reducing cash generated from operations and cash available for distribution.

We may experience delays in the payment of royalties 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.

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

However, we might not be able to find a replacement operator and, if we did, we might not be able to enter into a new lease on favorable terms within a reasonable period of time.

However, we might not be able to find a replacement operator 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 bankruptcy proceedings, in which case our right to enforce or terminate the lease for any defaults, including non-payment, may be substantially delayed or otherwise impaired.

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Please read Part I, Items 1 and 2.

“Business and Properties — Environmental Matters” for a description of the laws and regulations that affect our operators and that may affect us.

“Business and Properties — Environmental Matters” for a description of the laws and

regulations that affect our operators and that may affect us.

These and other potential regulations could increase the operating costs of our operators and delay production, which could reduce the amount of cash distributions to our unitholders.

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Several states where we own interests in oil and natural gas producing properties, including Colorado, North Dakota, Louisiana, Oklahoma, and Texas, have adopted regulations that could restrict or prohibit hydraulic fracturing in certain circumstances or require the disclosure of the composition of hydraulic-fracturing fluids.

For example, in Texas, the RRC published a final rule in October 2014 governing permitting or re-permitting of disposal wells that require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as

logs, geologic cross sections, and structure maps relating to the disposal area in question.

If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the RRC may deny, modify, suspend, or terminate the permit application or existing operating permit for that well.

Similarly, Oklahoma has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events.

In September 2021, the RRC issued a notice to operators in the Midland area to reduce saltwater disposal well actions and provide certain data to the Commission.

Oklahoma, similarly, has imposed strict limits on the operation of disposal wells in areas with increased instances of induced seismic events.

These existing or any new legal requirements establishing seismic permitting requirements or similar restrictions on the construction or operation of disposal wells for the injection of produced water likely will result in added costs to comply and affect our operators’ rate of production, which in turn could have a material adverse effect on our results of operations and financial position.

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For example, in April 2019, Colorado adopted legislation that requires the COGCC to prioritize public health and environmental concerns in its decisions and delegates considerable new authority to local governments to regulate surface impacts.

Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks.

In keeping with this legislation, the COGCC in November 2020 adopted revisions to several regulations to increase protections for public health, safety, welfare, wildlife, and environmental matters.

These revisions established more stringent setbacks (2,000 feet instead of 500 feet) on new oil and gas development and elimination of routine flaring and venting of natural gas at new or existing wells across the state, each subject to only limited exceptions.Some local communities have adopted additional restrictions for oil and gas activities, such as requiring greater setbacks.

We cannot predict what additional state or local requirements may be imposed in the future on oil and gas operations in the states in which we own interests.

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We do not have, and do not intend to obtain, coverage for gradual, long-term pollution events.

In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise or

that we will be able to maintain adequate insurance at rates we consider reasonable.

In addition, these policies do not provide coverage for all liabilities, and we cannot assure our unitholders that the insurance coverage will be adequate to cover claims that may arise or that we will be able to maintain adequate insurance at rates we consider reasonable.

A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations, and cash distributions to unitholders.

Increasing attention to environmental, social and governance (ESG) matters may impact our business

Increasing attention to, and social expectations on, companies to address climate change and other environmental and social impacts, investor and societal explanations regarding voluntary ESG disclosures, and increased consumer demand for alternative forms of energy may result in increased costs, reduced demand for our products, reduced profits, increased investigations and litigation, and negative impacts on our unit price and access to capital markets.

Increasing attention to climate change and environmental conservation, for example, may result in demand shifts for oil and natural gas products and additional governmental investigations and private litigation against us.

To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation or contribution to the asserted damage, or other mitigating factors.

Additionally, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.

In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters.

Such ratings are used by some investors to inform their investment and voting decisions.

Unfavorable ESG ratings may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment or other industries which could have a negative impact on our unit price and/or our access to and costs of capital.

Moreover, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively or recruit or retain employees, which may adversely affect our operations.

We rely on a few key individuals whose absence or loss could adversely affect our business.

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In place of default fiduciary duties, our partnership agreement imposes a contractual standard requiring our general partner and its directors and executive officers to act in good faith, meaning they cannot cause the general partner to take an action that they subjectively believe is adverse to our interests.

Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.

Such contractual standards allow our general partner and its directors and executive officers to manage and operate our business with greater flexibility and to subject the

actions and determinations of our general partner and its directors and executive officers to lesser legal or judicial scrutiny than would be the case if state law fiduciary standards were applicable.

Our partnership agreement restricts the situations in which remedies may be available to our unitholders for actions taken that might constitute breaches of duty under applicable Delaware law and breaches of the contractual obligations in our partnership agreement.

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• the market price of the common units may decline.

rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.

However, subject to certain exceptions, our partnership agreement does not authorize us to issue securities having preferences or rights with priority over or on a parity with the Series B cumulative convertible preferred units with respect to rights to share in distributions, redemption obligations, or redemption rights without Series B cumulative convertible preferred unitholder approval.

Distributions to Unitholders;

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Because we are a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner’s board of directors or to establish a compensation committee or a nominating and corporate governance committee.

In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder approval prior to certain unit issuances.

In addition, because we are a publicly traded partnership, the NYSE does not require us to obtain unitholder

approval prior to certain unit issuances.

Accordingly, unitholders will not have the same protections afforded to stockholders of certain corporations that are subject to all of the NYSE’s corporate governance requirements.

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If the Internal Revenue Service (“IRS”) were to treat us as a corporation for U.S.

federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders could be substantially reduced.

federal income tax purposes or we were to become subject to entity-level taxation for state tax purposes, then our cash distributions to common unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S.

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From time to time, members of Congress propose and consider substantive changes to the existing U.S.

federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment for publicly traded partnerships.

federal income tax laws that would affect publicly traded partnerships, including proposals that would eliminate our ability to qualify for partnership tax treatment.

Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships.

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federal income tax purposes.

We are unable to predict whether any of these changes or other proposals will ultimately be enacted or adopted.

We are unable to predict whether any of these changes or other proposals

will ultimately be enacted or adopted.

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

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Additionally, future federal or state legislation may impose new or increased taxes or fees on oil and natural gas extraction.

In past years, legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S.

From time to time, legislation has been proposed that would, if enacted into law, make significant changes to tax laws, including to certain key U.S.

federal income tax provisions currently available to oil and gas companies.

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and (iii) an extension of the amortization period for certain geological and geophysical expenditures.

Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation, to accompany lower U.S.

federal income tax rates.

Congress could consider, and could include, some or all of these proposals as part of future tax reform legislation.

Moreover, other more general features of tax reform legislation, including changes to cost recovery rules and to the deductibility of interest expense may be developed that also would change the taxation of oil and gas companies.

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For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase.

Similarly, taking advantage of opportunities to reduce our existing debt,

such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our common unitholders as taxable income without any increase in our cash available for distribution.

Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our common unitholders as taxable income without any increase in our cash available for distribution.

You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax due from you with respect to that income.

Tax gain or loss on disposition of our common units could be more or less than expected.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units.

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In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year.

However, subject to the exceptions in the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act,” discussed below), under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory.

For our 2020 taxable year, the CARES Act increases the 30% adjusted taxable income limitation to 50%, unless we elect not to apply such increase.

For purposes of determining our 50% adjusted taxable income limitation, we may elect to substitute our 2020 adjusted taxable income with our 2019 adjusted taxable income, which may result in a greater business interest expense deduction.

However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for “business interest” is limited to the sum of our business interest income and 30% of our “adjusted taxable income.” For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory.

If our “business interest” is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them.

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As a result, distributions to a non-U.S.

common unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S.

common unitholder who sells or otherwise disposes of a common unit will also be

subject to U.S.

common unitholder will be subject to withholding at the highest

applicable effective tax rate and a non-U.S.

common unitholder who sells or otherwise disposes of a common unit will also be subject to U.S.

federal income tax on the gain realized from the sale or disposition of that common unit.

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trade or business is generally required to withhold 10% of the "amount" realized by the transferor unless the transferor certifies that it is not a foreign person.

While the determination of a partner's "amount realized" generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the "amount realized" on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner's share of publicly traded partnership's liabilities.

The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022, and after that date, if effected through a broker, the obligation to withhold is imposed on the transferor’s broker.

While the determination of a partner's "amount realized" generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the "amount realized" on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner's share of publicly traded partnership's liabilities.

The Treasury regulations and other guidance from the IRS provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023.

Thereafter, 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.

Current and future prospective non-U.S.

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

We treat each purchaser of common units as having the same tax benefits without regard to the common units actually purchased.

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In addition to U.S.

federal income taxes, you likely will be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance, or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions.

we conduct business or own property now or in the future, even if you do not live in any of those jurisdictions.

We own assets and conduct business in several states, many of which impose a personal income tax and also impose income taxes on corporations and other entities.

You may be required to file state and local income tax returns and pay state and local income

taxes in these jurisdictions.

You may be required to file state and local income tax returns and pay state and local income taxes in these jurisdictions.

Further, you may be subject to penalties for failure to comply with those requirements.

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As one of the largest owners and managers of oil and natural gas mineral interests in the United States, we rely on electronic systems and networks to control and manage our business and have multiple layers of security to monitor, mitigate and manage these risks.

However, these systems and networks, as well as our operators’ systems and networks and third-party infrastructure and operations, such as pipelines and transportation facilities, may be subject to sophisticated and deliberate security attacks and security breaches,

which could lead to the corruption or loss of sensitive and valuable data or other disruptions.

In addition, our efforts to monitor, mitigate and manage these evolving risks may result in increased capital and operating costs, but there can be no assurance that such efforts will be sufficient to prevent attacks or breaches from occurring.

If we or our operators were to experience an attack or a breach and security measures failed, the potential consequences to our businesses and the communities in which we operate could be significant, including the corruption or loss of sensitive and valuable data, legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, damage to our reputation, and other disruptions of our operations, any of which could adversely affect our business.

In addition, as cyber attacks become increasingly sophisticated, and the regulatory framework for data privacy and security worldwide continues to evolve and develop, we may incur significant costs to modify, upgrade or enhance our security measures and we may face difficulties in fully anticipating or implementing adequate security measures or new or revised mandated processes and in generally mitigating potential harm.

Further, any actual or perceived failure to comply with any new or existing laws, regulations and other obligations could result in fines, penalties or other liability.

UNRESOLVED STAFF COMMENTS

4 unchanged sentences

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