What changed in this filing

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Item 1A. Risk Factors

2024-02-20 compared with 2023-02-23 · 66 added, 54 removed, 543 unchanged (18% of the section changed)

31 unchanged sentences

• trading in oil and natural gas derivative contracts;

• the level of consumer product demand, including as a result of global pandemics similar to COVID-19;

• the level of consumer product demand;

• weather conditions and natural disasters;

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military operations in the Middle East;

• global geopolitical conflict, including the ongoing war in Ukraine and the relationships between the United States and other countries, such as China and Russia;

• global geopolitical conflict, including the ongoing war in Ukraine, the conflict in the Middle East and the relationships between the United States and other countries, such as China and Russia;

• the proximity, cost, availability, and capacity of oil and natural gas pipelines and other transportation facilities;

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During the ten years prior to December 31, 2023, WTI market prices at Cushing, Oklahoma have ranged from a high of $123.64 per Bbl in 2022 to a low of $8.91 per Bbl in 2020.

On December 31, 2022, the WTI spot market price of oil was $80.16.

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.

On December 29, 2023, the last trading day of 2023, the WTI spot market price of oil was $71.89.

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 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 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 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.

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During the ten years prior to December 31, 2023, natural gas prices at Henry Hub have ranged from a high of $23.86 per MMBtu in 2021 to a low of $1.33 per MMBtu in 2020.

On December 31, 2022, the Henry Hub spot market price of natural gas was $3.52 per MMBtu.

On December 29, 2023, the last trading day of 2023, the Henry Hub spot market price of natural gas was $2.58 per MMBtu.

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.

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

natural gas exports.

If prices for natural gas 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 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.

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In addition, the third parties on whom we or our operators rely for transportation services are subject to complex federal, state, tribal, and local laws that could adversely affect the cost, manner, or feasibility of conducting our business.

In January 2024, the Biden administration announced that approvals for pending and future applications for certain new LNG facilities were being paused pending a review by the DOE that aims to assess whether climate effects should be more heavily considered in the authorization process for such LNG export projects.

It is too early to know the outcome of this review and any impact the results of such review may have on LNG export growth but slowing LNG export growth could adversely affect the demand for our products.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate.

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Numerous changes over time to the assumptions on which our reserve estimates are based, as described above, often result in the actual quantities of oil and natural gas that are ultimately recovered being different from our reserve estimates.

The estimates of reserves as of December 31, 2022, 2021, and 2020 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2022, 2021, and 2020, respectively, in accordance with the SEC guidelines applicable to reserve estimates for those periods.

The estimates of reserves as of December 31, 2023, 2022, and 2021 were prepared using an average price equal to the unweighted arithmetic average of hydrocarbon prices received on a field-by-field basis on the first day of each month within the years ended December 31, 2023, 2022, and 2021, respectively, in accordance with the SEC guidelines applicable to reserve

estimates for those periods.

Reserve estimates do not include any value for probable or possible reserves that may exist, nor do they include any value for unproved undeveloped acreage.

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

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.

In December 2023, we received notice that Aethon Energy (“Aethon”) was exercising the “time-out” provisions under its joint exploration agreements with us in Angelina and San Augustine counties in East Texas.

When natural gas prices fall below specified thresholds, Aethon may elect to temporarily suspend its drilling obligations for up to nine consecutive months and a maximum of 18 total months in any 48-month period.

Aethon has not previously invoked the time-out provisions under the agreements.

For more information, please read Part II, Item 7.

“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments.”

If any of these risks are realized, 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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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, 2022, we had outstanding borrowings of $10.0 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 2022 was $550.0 million with outstanding commitments of $375.0 million and the next semi-annual redetermination is scheduled for April 2023.

As of December 31, 2023, we had no outstanding borrowings 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 2023 was $580.0 million and we elected to maintain cash commitments at $375.0 million.

The next semi-annual redetermination is scheduled for April 2024.

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

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In the past, we have made substantial capital expenditures in connection with the acquisition of mineral and royalty interests and, to a lesser extent, participation in our non-operated working interests.

To date, we have financed capital expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, executed farmout agreements, and the issuance of equity securities.

While we are currently focused on organic growth of our existing assets and have farmed out most of our non-operated working interests, it is possible that we may need access to capital for those activities in the future.

To date, we have financed capital

expenditures primarily with funding from cash generated by operations, limited borrowings under our Credit Facility, executed farmout agreements, and the issuance of equity securities.

While we are currently focused on organic growth of our existing assets and have farmed out most of our non-operated working interests, we expect to make opportunistic acquisitions to complement our existing acreage positions and may need access to capital for those activities in the future.

In those cases, we may restrict distributions to fund acquisitions and participation in our working interests but eventually we may need capital in excess of the amounts we retain in our business or borrow under our Credit Facility.

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Operations on the properties in which we hold interests are subject to various federal, state, and local governmental regulations that may be changed from time to time in response to economic and political conditions.

Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes, plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation.

Matters subject to regulation include drilling operations, production and distribution activities, discharges or releases of pollutants or wastes,

plugging and abandonment of wells, maintenance and decommissioning of other facilities, the spacing of wells, unitization and pooling of properties, and taxation.

From time to time, regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of oil and natural gas wells below actual production capacity to conserve supplies of oil and natural gas.

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Please read Part I, Items 1 and 2.

"Business and properties — Environmental Matters — Hydraulic Fracturing" for a description of the laws and regulations that affect our operators and that may affect us.

"Business and properties — Environmental Matters — Hydraulic Fracturing" for a description of the laws and regulations that affect our

operators and that may affect us.

There has been increasing public controversy regarding hydraulic fracturing with regard to increased risks of induced seismicity, the use of fracturing fluids, impacts on drinking water supplies, use of water, and the potential for impacts to surface water, groundwater, and the environment generally.

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Legislative changes could cause operators to incur substantial compliance costs.

At this time, it is not possible to estimate the impact on our business of newly enacted or potential

federal or state legislation governing hydraulic fracturing.

At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal or state legislation governing hydraulic fracturing.

Operating hazards and uninsured risks may result in substantial losses to us or our operators, and any losses could adversely affect our results of operations and cash distributions to unitholders.

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Securities and Exchange Commission (“SEC”) released a proposed rule that would establish a framework for the reporting of climate risks, targets, and metrics.

A final rule is expected to be released early 2023, but we cannot predict what any such final rule may require.

A final rule is expected to be released in 2024.

We cannot predict what any such final rule may require.

As proposed, the SEC climate rule would impose burdensome and potentially costly emissions and other data gathering and reporting requirements on our operations, including, but not limited to, those related to risks to our operators arising from the physical impacts of climate change (i.e., flooding, water stress, extreme temperatures).

To the extent the rule imposes additional reporting obligations, we could face increased costs.

Separately, the SEC has announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s climate disclosures are misleading or deficient.

Such agency action could also increase the potential for private litigation.

Relatedly, California has enacted new laws requiring additional disclosure with respect to certain climate-related risks and GHG emissions reduction claims.

Non-compliance with these new laws may result in the imposition of substantial fines or penalties.

Other states are considering similar laws.

Any new laws or regulations imposing more stringent requirements on our business related to the disclosure of climate-related risks may result in reputation harms among certain stakeholders if they disagree with our approach to mitigating climate-related risks, increased compliance costs resulting from the development of any disclosures, and increased costs of and restrictions on access to capital to the extent we do not meet any climate-related expectations of requirements of financial institutions.

Relatedly, 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.

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.

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Our partnership agreement generally provides that any distributions are paid each quarter as follows:

(i) first, to the holders of Series B cumulative convertible preferred units equal to 7% per annum, subject to certain adjustments, and (ii) second, to the holders of common units.

(i) first, to the holders of Series B cumulative convertible preferred units equal to 7.0% of the face amount of the preferred units per annum through November 27, 2023, adjusted to 9.8% effective November 28, 2023 and subject to readjustment every two years thereafter, and (ii) second, to the holders of common units.

However, the Board could elect not to pay distributions for one or more quarters or at all.

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The amount of distributions we make, if any, and the decision to make any distribution at all will be determined by the Board.

If we make distributions, our Series B cumulative convertible preferred unitholders have priority with respect to rights to share in those distributions over our common unitholders for so long as our Series B cumulative convertible preferred

units are outstanding.

Please read Part II, Item 5.

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Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them.

Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our

liabilities to exceed the fair value of our assets.

Under Section 17-607 of the Delaware Act, we may not make a distribution to our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.

Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount.

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federal income tax purposes, and not being subject to a material amount of entity-level taxation.

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

If the 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 would be substantially reduced.

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federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative, or judicial changes or differing interpretations at any time.

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

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.

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.

Further, while unitholders of publicly traded partnerships are,

subject to certain limitations, generally entitled to a deduction equal to 20% of their allocable share of a publicly traded

partnership’s “qualified business income” (as further discussed below), this deduction is scheduled to expire with respect to

taxable years beginning after December 31, 2025.

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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The passage of any legislation as a result of these proposals or any similar changes in U.S.

federal income tax laws could increase costs or eliminate or postpone certain tax deductions that currently are available to us or our services providers with respect to oil and gas development.

federal income tax laws could increase costs or eliminate or postpone certain tax deductions that currently are available to us or

our services providers with respect to oil and gas development.

Any such changes could have an adverse effect on our financial position, results of operations, and cash flows.

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Moreover, the costs of any contest between us and the IRS will result in a reduction in cash available for distribution to our common unitholders and thus will be borne indirectly by our common unitholders.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such common unitholders' behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes an audit adjustment to our income tax return, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us.

To the extent possible under these rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return.

their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible, or effective in all circumstances.

If the IRS makes an audit adjustment to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such common unitholders' behalf.

If the IRS makes an audit adjustment to our income tax return, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us.

To the extent possible, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each common unitholder and former common unitholder with respect to an audited and adjusted return.

Although our general partner may elect to have our common unitholders and former common unitholders take such audit adjustment into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible, or effective in all circumstances.

As a result, our current common unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such common unitholders did not own common units in us during the tax year under audit.

If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties, and interest, cash available for distribution to our common unitholders might be substantially reduced and our current and former common unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustment that were paid on such common unitholders' behalf.

These rules are not applicable for tax years beginning on or prior to December 31, 2017.

Even if you, as a common unitholder, do not receive any cash distributions from us, you will be required to pay taxes on your share of our taxable income.

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A substantial portion of the amount realized from the sale of your common units, whether or not representing gain, may be taxed as ordinary income to you due to potential recapture items, including depreciation recapture.

Thus, you may recognize both ordinary income and capital loss from the sale of your common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units.

Thus, you may recognize

both ordinary income and capital loss from the sale of your common units if the amount realized on a sale of your common units is less than your adjusted basis in the common units.

Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year.

9 unchanged sentences

federal income tax, including IRAs and other retirement plans, may be unrelated business taxable income and may be taxable to them.

Tax-exempt entities should consult a tax advisor before investing in our common units.

Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them.Tax-exempt entities should consult a tax advisor before investing in our common units.

common unitholders will be subject to U.S.

taxes and withholding with respect to their income and gain from

owning our common units.

taxes and withholding with respect to their income and gain from owning our common units.

common unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S.

14 unchanged sentences

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 common 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 a publicly traded partnership's liabilities.

For a transfer of an interest in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker.

For a transfer of an interest in a publicly traded partnership that is effected through a broker, the obligation to withhold is imposed on the transferor’s broker.

Current and future prospective non-U.S.

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Because we cannot match transferors and transferees of our common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations.

A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you.

A successful IRS

challenge to those positions could adversely affect the amount of tax benefits available to you.

It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

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federal income tax consequences of loaning a partnership interest, a common unitholder whose common units are the subject of a securities loan may be considered to have disposed of the loaned common units.

In that case, the common unitholder may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the common unitholder may recognize gain or loss from this

Moreover, during the period of the loan, any of our income, gain, loss, or deduction with respect to those common units may not be reportable by the common unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income.

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We cannot be certain that our efforts to develop and maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future, or that we will be able to comply with our obligations under Section 404 of the Sarbanes-Oxley Act.

For example, Section 404 requires us, among

other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.

For example, Section 404 requires us, among other things, to annually review and report on, and our independent registered public accounting firm to attest to, the effectiveness of our internal controls over financial reporting.

Any failure to develop or maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations.

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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

LEGAL PROCEEDINGS

Although we may, from time to time, be involved in various legal claims arising out of our operations in the normal course of business, we do not believe that the resolution of these matters will have a material adverse impact on our financial condition or results of operations.

MINE SAFETY DISCLOSURES

Not applicable.

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