Competition and Markets

The oil and natural gas industry is highly competitive. The Sponsor competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many of these competitors are financially stronger than the Sponsor, but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Because the Sponsor and the third-party operators of the Underlying Properties are subject to competitive conditions in the oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.

Oil and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future prices for oil and natural gas will directly impact Trust distributions, estimates of reserves attributable to the Trust’s interests and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor the Sponsor can make reliable predictions of future oil and natural gas supply and demand or future product prices. Nevertheless, lower product prices generally will result in lower distributions, lower estimates of reserves attributable to the Trust’s interests and lower estimated and actual future net revenues to the Trust.

All the Trust’s assets are located in the United States. The operators of the Underlying Properties sell the oil and natural gas produced from the Underlying Properties to third-party purchasers in the United States. Demand for natural gas generally is higher in the winter months, but otherwise seasonal factors do not affect the Trust.

Description of Trust Units

Each Trust Unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights regarding his or her Trust Units as every other Trust unitholder has regarding his or her units. The Trust Units are in book-entry form only and are not represented by certificates. The Trust had 33,000,000 Trust Units outstanding as of March 25, 2022.22, 2024.

Distributions and Income Computations

Each month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s liabilities for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities. The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business day after the record date. In the event thatIf the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.

Unless otherwise advised by counsel or the Internal Revenue Service (“IRS”), the Trustee will treat the income and expenses of the Trust for each month as belonging to the Trust unitholders of record on the monthly record date. Trust unitholders generally will recognize income and expenses for tax purposes in the month the Trust receives or pays those amounts, rather than in the month the Trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example, the Trustee could establish a reserve in one month that would not result in a tax deduction until a later month.

Transfer of Trust Units

Trust unitholders may transfer their Trust Units in accordance with the Trust Agreement. The Trustee will not require either the transferor or transferee to pay a service charge for any transfer of a Trust Unit. The Trustee may require payment of any tax or other governmental charge imposed for a transfer. The Trustee may treat the owner of any Trust Unit as shown by its records as the owner of the Trust Unit. The Trustee will not be considered to know about any claim or demand on a Trust Unit by any party except the record owner. A person who acquires a Trust Unit after any monthly record date will not be entitled to the distribution relating to that monthly record date. Delaware law and the Trust Agreement govern all matters affecting the title, ownership or transfer of Trust Units.

Periodic Reports

The Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need to correctly report their share of the income and deductions of the Trust. The Trustee also causes to be prepared and filed reports that are required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading, and also causes the Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.

Each Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee, subject to such restrictions as are set forth in the Trust Agreement.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General Corporation Law of the State of Delaware. The courts in jurisdictions outside of Delaware, however, might not give effect to such limitation.

Voting Rights of Trust Unitholders

The Trustee or Trust unitholders owning at least 10% of the outstanding Trust Units may call meetings of Trust unitholders. The Trust is responsible for all costs associated with calling a meeting of Trust unitholders, unless such meeting is called by the Trust unitholders, in which case the Trust unitholders who called the meeting are responsible for all costs associated with calling such meeting.costs. Meetings must be held in such location as is designated by the Trustee designates in the notice of such meeting. The Trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust Units outstanding must be present or represented by proxy to have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned. Abstentions and broker non-votes shallwill not be deemed to be a vote cast.

Unless otherwise required by the Trust Agreement otherwise requires, a matter may be approved or disapproved by the affirmative vote of a majority of the Trust Units present in person or by proxy at a meeting where there is a quorum. This is true even if holders of a majority of the total Trust Units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding Trust Units is required to:

At theIn September 2017, following a special meeting of Trust unitholders held on August 30, 2017,at which unitholders approved amendments to the Trust Agreement. In September 2017,Agreement, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow Enduro (and, therefore, following the Sale Transaction, the Sponsor) to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from holders of 75% to holders of 50% of the outstanding units of the Trust.Trust Units.

In addition, the Trustee may make certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders.

Computation of Net Profits

The provisions of the Conveyance governing the computation of the net profits are detailed and extensive. The following information summarizes the material provisions of the Conveyance related to the computation of the net profits, but is qualified in its entirety by the text of the Conveyance, which is incorporated by reference as an exhibit to this Form 10-K.

Net Profits Interest

The amounts paid to the Trust forwith respect to the Net Profits Interest are based on, among other things, the definitions of “gross profits” and “net profits” contained in the Conveyance and described below. Under the Conveyance, net profits are computed monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar month will be paid to the Trust on or before the end of the following month. The Sponsor will not pay to the Trust any interest on the net profits held by the Sponsor prior to payment to the Trust, provided that such payments are timely made.

“Gross profits” means the aggregate amount received by the Sponsor from and after July 1, 2011 from sales of oil and natural gas produced from the Underlying Properties that are not attributable to a production month that occurs prior to June 1, 2011 (after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges (in each case, in existence as of June 1, 2011) and other than certain excluded proceeds, as described in the Conveyance), including all proceeds and consideration received (i) directly or indirectly, for advance payments, (ii) directly or indirectly, under take-or-pay and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by the Sponsor or any subsequent owner to any new owner, unless the Net Profits Interest is released (as is permitted under certain circumstances). Gross profits also do not include any amount for oil or natural gas lost in production or marketing or used by the owner of the Underlying Properties in drilling, production and plant operations.

“Net profits” means, as more fully set forth in the Conveyance, gross profits less the following costs, expenses and, where applicable, losses, liabilities and damages all as actually incurred by the Sponsor and attributable to the Underlying Properties on or after July 1, 2011 but that are not attributable to a production month that occurs prior to July 1, 2011 (as such items are reduced by any offset amounts, as described in the Conveyance):

As mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts are further described in the Conveyance, and include, among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties and certain non-production revenues, including salvage value for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs arising in such month.

The Trust is not liable to the owners of the Underlying Properties or the operators for any operating capital or other costs or liabilities attributable to the Underlying Properties. The Trustee expects to make distributions to Trust unitholders monthly; however, in the event thatif the net profits for any computation period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation period.

The Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interestnet profits and payments of expenses incurred. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust with respect to the corresponding production month pursuant to terms of the Conveyance.

Additional Provisions

If a controversy arises as to the sales price of any production, then for purposes of determining gross profits:

The Trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the Trust by the Sponsor due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the Trust until the Sponsor recovers the overpayments plus interest at a prime rate (as described in the Conveyance).

The Conveyance generally permits the Sponsor to transfer without the consent or approval of the Trust unitholders all or any part of its interest in the Underlying Properties, subject to the Net Profits Interest. The Trust unitholders are not entitled to any proceeds of a sale or transfer of the Sponsor’s interest. Except in certain cases where the Net Profits Interest is released, following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interest, and the gross profits attributable to the transferred property will be calculated, paid and distributed by the transferee to the Trust. The Sponsor will have no further obligations, requirements or responsibilities with respect to any such transferred interests.

In addition, the Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with any lease that accounts for lessno more than or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by the Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the Trust of such Net Profits Interest being treated as an offset amount against costs and expenses. In September 2021,May 2023, the Sponsor entered into a lease arrangement with respectsold approximately $0.3 million in non-producing, non-cash flowing acreage to a portionprivate oil company, free and clear of the mineral rights relating to certain ofNet Profits Interest, as permitted under the Underlying Properties located in Borden County, Texas, for total estimatedTrust Agreement. The proceeds of $82,500 (approximately $63,000 netfrom this sale attributable to the Trust’s 80% Net Profits Interest).Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

As the designated operator of a property included in the Underlying Properties, the Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interest. The Sponsor may enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.

The Sponsor has the right to release, surrender or abandon its interest in any Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities (determined without regard to the Net Profits Interest). Upon such release, surrender or abandonment, the portion of the Net Profits Interest relating to the affected property will also be released, surrendered or abandoned, as applicable. The Sponsor also has the right to abandon an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or environmental reasons or (b) the hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be expected to be produced from wells located on the remaining portion of the Underlying Properties.

The Sponsor must maintain books and records sufficient to determine the amounts payable forto the Trust with respect to the Net Profits Interest to the Trust.Interest. Monthly and annually, the Sponsor must deliver to the Trustee a statement of the computation of the net profits for each computation period. The Trustee has the right to inspect and review the books and records maintained by the Sponsor during normal business hours and upon reasonable notice. The Sponsor has further agreed to provide the Trust and Trustee with all information and services as are reasonably necessary to fulfill the purposes of the Trust, including such accounting, bookkeeping and informational services as may be necessary for the preparation of reports the Trust is required to prepare or file in accordance with applicable tax and securities laws, exchange listing rules and other requirements, including reserve reports and tax returns. Following the sale of all or any portion of the Underlying Properties, the purchaser will be bound by the obligations of the Sponsor under the Trust Agreement and the Conveyance with respect to the portion sold.

U.S. Federal Income Tax Matters

The following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income tax matters affecting the Trust or the Trust unitholders.

The summary has limited application to non-U.S. persons and persons subject to special tax treatment such as, without limitation: banks, insurance companies or other financial institutions; Trust unitholders subject to the alternative minimum tax; tax-exempt organizations; dealers in securities or commodities; regulated investment companies; real estate investment trusts; traders in securities that elect to use a mark-to-market method of accounting for their securities holdings; non-U.S. Trust unitholders that are “controlled foreign corporations” or “passive foreign investment companies”; persons that are S-corporations, partnerships or other pass-through entities; persons that own their interest in the Trust Units through S-corporations, partnerships or other pass-through entities; persons that at any time own more than 5% of the aggregate fair market value of the Trust Units; expatriates and certain former citizens or long-term residents of the United States; U.S. Trust unitholders whose functional currency is not the U.S. dollar; persons who hold the Trust Units as a position in a hedging transaction, “straddle”, “conversion transaction” or other risk reduction transaction; or persons deemed to sell the Trust Units under the constructive sale provisions of the Code. Each Trust unitholder should consult his or her own tax advisor with respect to his or her particular circumstances.

Classification and Taxation of the Trust

Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested from the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust, the Trust is not subject to U.S. federal income tax at the trust level. Rather, each Trust unitholder is considered for U.S. federal income tax purposes to own its proportionate share of the Trust’s assets directly as though no Trust were in existence. The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of the income and gain attributable to the assets of the Trust and is entitled to claim its proportionate share of the deductions and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.

The Trust files annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit. The Trust allocates these items of income, gain, loss, deduction and credit to Trust unitholders based on record ownership on the monthly record dates. It is possible that the IRS or another taxing authority could disagree with this allocation method and assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require adjustments to the tax returns of the unitholders affected by this issue and result in an increase in the administrative expense of the Trust in subsequent periods.

Under current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gainsgains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is generally 20%. Such marginal tax rates may be effectively increased due to the phaseout of personal exemptions and certain limitations and prohibitions on itemized deductions. The highest marginal U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and capital gains.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts (and a reduced 1.4% tax on certain tax-exempt organizations). For these purposes, investment income generally will include a unitholder’s allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s U.S. federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate or trust begins.

If a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Code, the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The IRS likely will take the position that a unitholder must recapture depletion upon the disposition of a unit.

Classification of the Net Profits Interest

Tax counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, based upon the reserve report and representations made by the Trust regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interest, in its opinion the Net Profits Interest attributable to proved developed reserves will and the Net Profits Interest attributable to proved undeveloped reserves should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the mineral interests they burden. No assurance can be given that the IRS or another taxing authority will not assert that the Net Profits Interest should be treated differently. Any such different treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in Trust Units.

Reporting Requirements for Widely-Held Fixed Investment Trusts

The Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Houston, Texas 77002, telephone number 1-512-236-6545, is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.

Available Trust Tax Information

In compliance with the Treasury regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns. This tax information booklet can be obtained at www.permianvilleroyaltytrust.com.

Environmental Matters and Regulation

General.For purposes of the discussion in this section, the oil and natural gas production operations conducted on the properties that are subject to the Net Profits Interest are referred to as the “Sponsor’s operations.” The Sponsor’s oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may impose significant obligations on the Sponsor’s operations, including requirements to:

Failure to comply with environmental laws and regulations may result in the assessment of significant administrative, civil and criminal sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or all of the Sponsor’s operations. Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. The Sponsor has advised the Trustee that it believes that it is in substantial compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders. Although the Trump Administration had taken steps aimed at reducing federal regulatory burdens and costs for oil and natural gas production operations, the recent trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could have a material adverse effect on the Sponsor’s development expenses, results of operations and financial position. The Sponsor may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course of the Sponsor’s operations, and there can be no assurance that the Sponsor will not incur significant costs and liabilities as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

The following is a summary of certain existing environmental, health and safety laws and regulations to which the Sponsor’s business operations are subject.

Hazardous substance and wastes. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,”as amended (“CERCLA”), also known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be jointly and severally responsible for the release of a “hazardous substance” into the environment. These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these “responsible persons” may be liable for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Although petroleum, natural gas, and natural gas liquids are excluded from the definition of “hazardous substance” under CERCLA, the Sponsor generateshandles materials in the course of its operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

The Sponsor also generates solid and hazardous wastes that are subject to the requirements of the Resource Conservation and Recovery Act, or “RCRA,”as amended (“RCRA”), and comparable state laws regulatestatutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation treatment, storage,and disposal and cleanup of hazardous wastes. In the course of its operations, The Sponsor generates petroleum hydrocarbon wastes and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all the provisions ofordinary industrial wastes that may be classified as hazardous wastes under RCRA sometimes in conjunction with their own, more stringent requirements.and comparable state laws. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, production, and development of crude oil or natural gas are currently regulated under the RCRA as non-hazardous wastes. Nevertheless, it is possible that certain oil and natural gasWhile many exploration and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related oil and natural gas wastesare exempt from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. The EPA fulfilled its obligation under the consent decree by issuing a determination on April 23, 2019 that revisions to existing RCRA Subtitle D regulations governing oil and natural gaswaste, these wastes are not necessary, alonggenerally subject to non-hazardous waste regulation under RCRA and applicable state regulations. Many state governments have specific regulations and guidance for exploration and production wastes, including the wastes associated with a report supporting that determination. In addition, the Sponsor generates industrial wastes in the ordinary course of its operations that may be regulated as hazardous wastes. Such wastes must be properly tested, characterized and disposed of according to state and federal regulations.hydraulic fracturing activities.

The properties upon which the Sponsor conducts its operations have been used for oil and natural gas exploration and production for many years. Although the Sponsor and, as applicable, the Sponsor’s predecessor, Enduro, may have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released at or from the real properties upon which the Sponsor conducts its operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for treatment or disposal. In addition, the properties upon which the Sponsor conducts its operations may have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was not under the Sponsor’s control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, the Sponsor could be required to investigate, remove or remediate previously disposed wastes, to clean up contaminated property and to perform response actions to prevent future contamination or to pay some or all of the costs of any such action.contamination.

Water discharges. The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls regardingon the discharge of pollutants into water“waters of the United StatesStates” and waters within the scope of the state law, respectively. Pursuant to the CWA and analogousapplicable state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States.regulated waters. Any such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by the EPA or the analogousapplicable state agency.agency or both. The discharge of wastewater from most onshore oil and gas exploration and production activities is currently prohibited east of the 98^th meridian. Additionally, in June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending certain wastewater directly to publicly owned treatment works (“POTW”). Unconventional extraction facilities are allowed by 40 CFR Part 437 to send wastewater to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances. CWT facilities can either discharge treated water directly to surface waters or send it to a POTW. In 2018, the EPA concluded a study of the treatment and discharge of oil and gas wastewater that could lead to changes in requirements for discharge of produced water under Part 437, including more stringent requirements or a prohibition on discharge of produced water from CWT facilities. Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge requirements may result in increased costs.

The discharge of dredge and fill material in waters of the United States, including wetlands, is also prohibited unless authorized by a permit issued under CWA Section 404 by the U.S. Army Corps of Engineers (“USACE”). CWA Section 401 provides that the applicant for an individuala Section 404 USACE permit for the discharge of dredge and fill materials must notifyseek a Section 401 water quality certification by applying to the state in which the discharge will occur and provide an opportunity for the state to determine if the discharge will comply with the state’s approved water quality program. In some instances, this process could result in delay in issuance of the permit, more stringent permit requirements, or denial of the permit.

How the EPA and the USACE define “waters of the United States” (“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, can impact the Sponsor’s regulatory and permitting obligations under the CWA. In 2020,2023, the EPA and the USACE issued a final rule (“2020(the “2023 rule”) that narrowed the definition of WOTUS when compared to the prior definition of WOTUS that had been adopted in 2015. In August 2021, however, a court vacated the 2020 rule. In response,is described by the EPA and the USACE reverted toas following the WOTUS definition in use prior to the 2015 WOTUS rulemaking. That pre-2015 definition is broader than the definition from the 2020 rule, but was never formally codified because it was based on interpretation of a1986 regulations as modified by subsequent U.S. Supreme Court decision. On December 7, 2021,decisions and guidance issued by the agencies publishedEPA and USACE interpreting the decisions. Shortly thereafter, the Supreme Court issued its decision in Sackett II which overturned a proposedsubstantial portion of the basis for the 2023 Rule. USACE and the EPA subsequently amended the 2023 rule that would codifyand excluded a number of types of wetlands and streams from CWA jurisdiction, but the interpretation currently in use. The comment period closed in February 2022 and a final rule is expected later in 2022. Atsubject to litigation regarding the same time, the U.S. Supreme Court has taken up a case that may again revise the understandingsufficiency of the WOTUS definition.agencies’ interpretation of the Sackett II decision. The Sponsor’s regulatory obligations and permitting costs may increase under the current definition as opposedwill continue to the one in effect under the 2020 rule, and there will remain somebe subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given expected challenges to the 2022 final rule and the pending Supreme Court case.ongoing litigation.

USACE Nationwide Permits (“NWPs”) are a streamlined form of permitting used to authorize development activities with minimal individual or cumulative adverse effects in wetlands or other waters of the United States under the CWA and/orCWA. Some NWPs are also used to authorize activities that impact traditional navigable waters under the Rivers and Harbors Act. The current administration has stated an intention to re-visit all or someNWP 12, which is used to authorize regulated impacts related to construction of the USACE NWPsoil and gas pipelines, through notice and comment rulemaking before theirits current expiration date of February 2026. In addition, a federal court in MontanaWashington, D.C. is currently hearing a challenge to NWP 12, which is used to authorize regulatory impacts related to oil and gas pipelines.12. Revisions to the NWPsNWP 12 by USACE or an adverse decision in MontanaWashington, D.C. may restrict or remove the ability to use NWP 12 or other NWPs to permit regulated impacts, resulting in the need to apply for a more time-consuming individual permit. This could result in additional cost and time for permitting projects.

Finally, the Oil Pollution Act of 1990, as amended or “OPA,”(“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills from reaching nearby waterbodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities in certain instances to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. The Sponsor has developed and implemented SPCC plans for the Underlying Properties as required under the CWA.

Hydraulic fracturing. Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock formation to stimulate production of oil and natural gas. The U.S. Congress has considered legislation to amend the federal Safe Drinking Water Act (“SDWA”) to subject hydraulic fracturing operations to regulation under the SDWA’s Underground Injection Control Program and to require the disclosure of chemicals used in the hydraulic fracturing process. Any such legislation could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against companies. In addition, the federal government is currently undertaking several studies of hydraulic fracturing’s potential impacts. The Secretary of Energy Advisory Board published their ninety-day report that included a number of recommendations. In December 2016, the EPA issued a final report on the potential impacts of hydraulic fracturing on drinking water resources. The report did not find widespread, systematic impacts to drinking water from hydraulic fracturing; at the same time, the report acknowledged information gaps that limited EPA’s ability to fully assess the potential impacts to drinking water resources. In addition, as noted above, the EPA in June 2016 issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater directly to POTWs. EPA is conducting a related study of oil and gas extraction wastewater at private wastewater treatment facilities. In March 2015, the federal Bureau of Land Management (“BLM”) released a final rule establishing new or more stringent standards for performing hydraulic fracturing operations on federal and tribal lands. Several states, trade groups and companies have challenged the legality of the BLM rule in federal court. On September 30, 2015, the U.S. District Court for the District of Wyoming issued a preliminary injunction, blocking BLM from enforcing the new rules nationwide, and on June 21, 2016, the court issued a final ruling striking down the BLM rule. While the U.S. Department of Interior initially has appealed the decision to the Tenth Circuit Court of Appeals. BLM announced in March 2017 that it intended to rescind the rule. On December 29, 2017, BLM published a final rule that rescinded the 2015 hydraulic fracturing rule.

On August 16, 2012 the EPA published final rules that extend New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAPs”) to certain exploration and production operations. The final rule requires the use of reduced emission completions or “green completions” on all hydraulically-fracturedhydraulically fractured gas wells constructed or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response to some of these challenges, the EPA amended the rule to extend compliance dates for certain storage vessels and may issue additional revised rules in response to additional such requests in the future. Only a portion of these new rules appear to affect the Sponsor’s operations at this time by requiring new air emissions controls, equipment modification, maintenance, monitoring, recordkeeping and reporting. Although these new requirements will increase the Sponsor’s operating and capital expenditures and it is possible that the EPA will adopt further regulation that could further increase the Sponsor’s operating and capital expenditures, the Sponsor does not currently expect such existing and new regulations will have a material adverse impact on its operations or financial results.

Some states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used in the hydraulic fracturing process. Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, the Sponsor’s and the third-party operators’ fracturing activities could become subject to additional permit requirements or operational restrictions, to associated permitting delays and potential increases in costs. In December 2014, the Governor of New York announced that the state would maintain its moratorium on hydraulic fracturing in the state. Further, some local governments, including in Texas, have imposed moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities. Similar measures could be considered or implemented in the jurisdictions in which the Underlying Properties are located.

Air emissions. The federal Clean Air Act, as amended (“CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and also impose various monitoring and reporting requirements. These laws and regulations may require the Sponsor to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, and to comply with stringent air emissions permit or regulatory requirements or utilize specific equipment or technologies to control emissions. Obtaining permits has the potential to delay the development of the Sponsor’s properties.

The EPA has established pollution control standards for oil and gas sources under the CAA. In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels.vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, in December 2023 the EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. Additionally, the EPA for the first time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources. The existing source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The EPA is also charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact the Sponsor’s operations. The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard. The current administration will have an opportunity to revisit the ozone NAAQS. In addition, on January 20, 2021, President Biden issued an executive order calling onMore recently, however, in February 2024, the EPA to proposeannounced a Federal Implementation Plan forfinal rule that will lower the ozoneannual standard for certain states by January 2022, in responsefine particulate matter from 12 micrograms per cubic meter to those states’ failure to submit an adequate state plan for the control of ozone precursor emissions from certain oil and gas sources. 9 micrograms per cubic meter.

State or federal implementation of the NAAQS could result in stricter permitting or regulatory requirements, delay or prohibit the Sponsor’s ability to obtain such permits, and result in increased expenditures for pollution control equipment. Although the Sponsor may be required to incur certain capital expenditures during the next few years for air pollution control equipment or other air emissions-related issues, at this time the Sponsor does not expect that such requirements will have a material adverse effect on its operations.

Climate change. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed oil and gas sources—as well as the EPA’s recently adopted methane emissions guidelines for existing oil and gas sources. The EPA also has adopted rules requiring the reporting of GHG emissions from specified large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis. In addition, the EPA has recently proposed rules to implement the mandatory Waste Emissions Charge set forth in the Inflation Reduction Act of 2022 (the “IRA”), which will charge a fee based on the methane emissions from applicable facilities in the oil and gas sector starting in 2024.

The EPA has established pollution control standards for oil and gas sources under the CAA. In December 2015, the EPA finalized rules that added new sources to the scope of its GHG monitoring2012 and reporting rule. These new sources include gathering and boosting facilities. The revisions also include the addition of well identification reporting requirements for certain facilities. In addition, in June 2016, the EPA publishedadopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific requirements limiting emissions from production-related wet seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks. These NSPS apply to sources that are newly constructed or modified after the rules’ applicability dates. More recently, in December 2023 the EPA adopted a final rule that requires operators to reducewill directly regulate volatile organic compound and methane emissions from certainnew oil and gas facilities, that are constructed, modified, or reconstructed after September 18, 2015 (the “Methane Rule”). Followingsources and will require further reductions in emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and equipment leaks. At the November 2016 presidential election and change in administrations,same time, the EPA convened a reconsideration proceeding that culminated in a 2020 final rule that eliminated the obligation to control methane emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements because they serve to control emissions of other pollutants. That 2020 final rule, however, was undone by a June 30, 2021 Congressional Review Act resolution that re-instituted the regulation of methane from new, modified, and reconstructed oil and gas sources. Additionally, on November 15, 2021, the EPA published a proposed rule that would establishadopted emissions guidelines for the control of methane fromthat will apply to existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for the first time under the CAA.new sources. The EPA intends to adopt the existing source emissions guidelines as a final rule byare to be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The IRA included new Clean Air Act section 136(c) directing the end of 2022, which would then trigger a requirement for statesEPA to develop rules that will makecollect the federal emissions guidelines enforceable as state rules over a three- to four-year period. The ultimate fate ofWaste Emissions Charge from facilities in the proposed GHG control requirements for existing oil and gas sources is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsorsector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to incur development expenses to install and utilize specific equipment, technologies, or work practices to control methane emissions from its operations.calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established “methane intensity figures” that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions, and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance with EPA’s new or existing source methane requirements. The EPA proposed new rules to implement the Waste Emissions Charge program in January 2024.

MoreAdditionally, more than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. In addition, from time to time Congress has considered adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives could have a material adverse effect on the Sponsor’s business, capital expenditures, financial condition and results of operations.

At the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals every five years beginning in 2020. While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements. In November 2019, however, plans were formally announced for the U.S. to withdraw from the Paris Agreement, and the U.S.’s withdrawal from the Paris Agreement took effect on November 4, 2020. On January 20, 2021, President Biden issued an executive order commencing the process to reenter the Paris Agreement, although the emissions pledges in connection with that effort have not yet been updated. The U.S. formally rejoined the Paris Agreement in February 2021. The Trust cannot predict whether re-entry into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements will cause the Sponsor to incur material costs.

In a separate executive order issued on January 20, 2021, President Biden asked the heads of all executive departments and agencies to review and take action to address any Federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with or present obstacles to the administration’s stated goals of protecting public health and the environment, and conserving national monuments and refuges. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane,” which are “the monetized damages associated with incremental increased in greenhouse gas emissions,” including “changes in net agricultural productivity, human health, property damage from increased flood risk, and the value of ecosystem services.” The Working Group is expected to issue its recommendations in early 2022.

The adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Sponsor’s equipment and operations could require the Sponsor to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas it produces. Legislation or regulations that may be adopted to address climate change could also affect the markets for the Sponsor’s products by making its products more or less desirable than competing sources of energy. To the extent that its products are competing with higher GHG-emitting energy sources, the Sponsor’s products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with lower GHG-emitting energy, the Sponsor’s products may become less desirable in the market with more stringent limitations on greenhouse gas emissions. The Sponsor cannot predict with any certainty at this time how these possibilities may affect its operations.

Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such significant physical effects were to occur, they could have an adverse effect on the Sponsor’s assets and operations and cause the Sponsor to incur costs in preparing for and responding to them. Additionally, energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.

National Environmental Policy Act. The National Environmental Policy Act (“NEPA”) requires the federal government to undertake an environmental review prior to making a decision on most proposed federal actions – such as permits, leases, and rights-of-way. The Trump Administration significantly revised the regulations implementing NEPA in 2020 in an effort to make the review process more efficient and more narrowly tailored to the agency’s specific action. The Biden Administration is in the process ofundertook an initial revision to the NEPA regulations andwhich were finalized in October 20212022, essentially reverting to the pre-2020 rule language for a few elements of the rules. In 2023, the Biden Administration issued a second proposed rule that would make significant changes to the Trump Administration regulations. The proposed rule is expected to be finalized in April 2024. In addition, in early 2023 the White House Council on Environmental Quality (“CEQ”) published a proposed rule that would undo manyissued Guidance to the federal agencies on how agencies should consider greenhouse gas emissions and climate impacts in the course of their reviews under NEPA. Although the changes adopted in 2020. The current administration has also stated its intention to undertake a second and more comprehensive round of revisions. The immediateTrump Administration regulations were never fully implemented, the Biden Administration changes may not have a significantmeaningful impact on federal reviews related to the Sponsor’s actions because the Trump Administration rule was never fully implemented by the agencies; however, continued change may increase agency review times associated with federal actionsSponsor, especially as agencies adjustthose reviews relate to changing requirementsclimate and react to any resulting litigation.environmental justice.

Endangered Species Act. The federal Endangered Species Act, as amended (“ESA”), restricts activities thatprohibits take of listed endangered, and in some cases threatened, species. Under the ESA, federal agencies are obligated to consult with the U.S. Fish and Wildlife Service or National Marine Fisheries Service if an agency’s actions, including permit actions, may affect endangered and threatenedlisted species or their habitats.designated critical habitat. If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required.required, depending on the implications for protected species and designated critical habitat. On August 27, 2019, the U.S. Fish and Wildlife Service published a final rule adopting several changes to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing species from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat. In January 2021, President Biden issued an Executive Order announcing that the new administration would initiate a review of the 2019 amendments to the ESA rules. The Biden Administration has rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and has stated its intentionissued a proposed rule that would make significant changes to revise other rules.the federal consultation process. That rule is expected to be finalized by the Biden Administration. Changes to these rules could make a federal review process occasioned by the application for permits, rights of way, or leases more complex. DesignationIn addition, designation of new species as threatened or endangered could cause the Sponsor to incur additional costs arising from species protection measures, could result in limitations on activities, and could require a more complex regulatory compliance process.

Employee health and safety. The operations of the Sponsor are subject to a number of federal and state laws and regulations, including the federal Occupational Safety and Health Act, as amended (“OSHA”), and comparable state statutes, whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Where You Can Find Other Information

The Trust maintains a website at http://www.permianvilleroyaltytrust.com. The Trust’s filings under the Exchange Act are available at this website and are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition, the Trust will provide electronic copies of its recent filings free of charge to the Trust unitholders upon request to the Trustee.

Summary of Risk Factors

The risk factors summarized and detailed below could materially harm production from the Underlying Properties, operating results and/or the Trust’s financial condition, adversely affect proceeds to the Trust and cash distributions to Trust unitholders, and/or cause the price of the Trust Units to decline. These are not all the risks the Trust faces, and other factors not presently known to the Trust or that the Trust currently believes are immaterial may also affect the Trust if they occur. These risks and uncertainties include, but are not limited to, the following:

Business and Operating Risks

Financial Risks

Risks Related to the Structure of the Trust

Risks Related to Ownership of the Trust Units

Legal, Environmental and Regulatory Risks

Cybersecurity Risks

Tax Risks Related to the Trust Units

BUSINESS AND OPERATING RISKS

Prices of oil and natural gas fluctuate, and lower prices could reduce proceeds to the Trust and cash distributions to Trust unitholders.

The Trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural gas. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and the Sponsor. These factors include, among others:

·       regional, domestic and foreign supply and perceptions of supply of oil and natural gas;

·       the level of demand and perceptions of demand for oil and natural gas;

·       political conditions or hostilities in oil and natural gas producing regions;

·       anticipated future prices of oil and natural gas and other commodities;

·       weather conditions and seasonal trends;

·       technological advances affecting energy consumption and energy supply;

·       U.S. and worldwide economic conditions;

·       the price and availability of alternative fuels;

·       the proximity, capacity, costThese factors and availability of gathering and transportation facilities;

· the volatility of the energy markets make it extremely difficult to predict future oil and uncertainty of regional pricing differentials;

·       governmental regulations and taxation;

·       energy conservation and environmental measures; and

·       acts of force majeure.

Crude oilnatural gas price movements with any certainty. Commodity prices have been volatile over the last two yearsdisplayed dramatic volatility in response to the economic effects of2020, when the COVID-19 pandemic and other factors affectingvarious governmental actions taken to mitigate the global economy. Lowimpact of COVID-19 resulted in an unprecedented decline in demand for oil and natural gas. The effects of the economic disruption caused by the governmental responses to the COVID-19 pandemic continued to be felt through 2023, in the form of lingering supply chain disruptions, higher inflation and higher interest rates, which affected supply and demand for oil and natural gas. Meanwhile, as strains or variants of COVID-19 resurge, or if other epidemic or pandemic diseases or other public health event were to occur, the negative impact to global demand for oil and natural gas could be material.

A substantial or extended decline in oil or natural gas prices will reduce profits to which the Trust is entitled which will reduceand therefore the amount of eachcash available for distribution to Trust unitholders, and unitholders. A prolonged period of low oil or natural gas prices may ultimately reduce the amount of oil and natural gas that is economically viable to produce from the Underlying Properties. As a result, the operators of the Underlying Properties could determine during periods of low commodity prices to shut-in or curtail production from wells on the Underlying Properties, or even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result in termination of the Net Profits Interest relating to the abandoned well or property.

The Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance, downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result, decreasing commodity prices may cause the expenses of certain wells to exceed the well’s revenue, in which case the operator may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to Trust unitholders. Sustained lower prices of oil and natural gas also could negatively affect the price of the Trust Units and the qualification of the Trust Units to remain listed on the New York Stock Exchange.

The Sponsor has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced on behalf of the Trust, and the terms of the Conveyance of the Net Profits Interest prohibit the Sponsor from entering into new hedging arrangements burdening the Trust. As a result, all production in which the Trust has an interest is unhedged, and the amount of the cash distributions isavailable for distribution may be subject to the possibility of greater fluctuations due to changes in oil and natural gas prices.

The ongoing COVID-19 pandemic and related economic turmoil have affected and could continue to adversely affect proceeds to the Trust and quarterly cash distributions to Trust unitholders.

The COVID-19 pandemic and the measures put in place to address it have created significant volatility, uncertainty, and economic disruption since the first quarter of 2020. Over the course of the pandemic, public health officials have recommended or mandated certain precautions to mitigate the spread of COVID-19, including quarantines, shelter-in-place orders and business and government shutdowns. Although some of these limitations and mandates have been relaxed in certain jurisdictions, others have been reinstated in areas that have experienced a resurgence of COVID-19 cases and there is no guarantee restrictions will not be reimposed in the future. Despite the increased availability of vaccines in certain jurisdictions, the COVID-19 pandemic may continue or worsen during the upcoming months, including as a result of the emergence of more infectious variants of the virus, vaccine hesitancy or increased business and social activities, which may cause governmental authorities to reinstate restrictions. As a result, the ongoing impact of the COVID-19 pandemic remains uncertain and will depend on the severity, location and duration of the effects and spread of the disease, the effectiveness and duration of actions taken by authorities to contain the virus or treat its effect, the availability and effectiveness of vaccines or other treatments, and how quickly and to what extent economic conditions improve. 

Furthermore, the impact of the pandemic has led to significant global economic contraction generally, and in the oil and gas industry in particular, which experienced a significant downturn during 2020 and into 2021. Since the beginning of 2020, the West Texas Intermediate spot price of crude oil has ranged widely in response to the economic effects of the COVID-19 pandemic and other factors affecting the global economy. Oil and natural gas prices are expected to continue to be volatile, and the Trust cannot predict when prices will stabilize. The Trust cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have on the Sponsor’s business, financial condition and results of operations or on proceeds to the Trust and the Trust’s reserves and quarterly cash distributions to Trust unitholders due to numerous uncertainties.

The extent to which the COVID-19 pandemic negatively affects the operators of and production from the Underlying Properties will depend on the severity, location and duration of the effects and spread of COVID-19, the actions undertaken by federal, state and local governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions improve and normal business and operating conditions resume. A prolonged period of low crude oil and natural gas prices will adversely affect the operators of the Underlying Properties. If commodity prices for crude oil and natural gas remain volatile and below historical levels, monthly cash distributions to Trust unitholders will be substantially lower than historical distributions, and in certain periods there may be no distribution to unitholders. Continued low oil and natural gas prices may ultimately reduce the amount of oil and natural gas that is economically viable to produce from the Underlying Properties. As a result, the operators of the Underlying Properties could determine during periods of low commodity prices to shut-in or curtail production from wells on the Underlying Properties, or even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities, which could result in termination of the Net Profits Interest relating to the abandoned well or property. Future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated commodity prices could result in recognition of impairment in future periods.

The ultimate impact of COVID-19 will depend on future developments, which are highly uncertain, difficult to predict and largely outside of the Trust’s control, including, among others, the continued spread, duration and severity of the pandemic; the occurrence, spread, duration and severity of any subsequent variants of COVID-19; the consequences of governmental and other measures designed to prevent the spread of the virus; the development of effective treatments; actions taken by governmental authorities, the Sponsor’s customers and other third parties; workforce availability; and the timing and extent to which normal economic and operating conditions resume.

To the extent COVID-19 adversely affects production from the Underlying Properties or the business, results of operations and financial condition of the operators of the Underlying Properties, it may also have the effect of heightening many of the other risks described in this Form 10-K.

Actual reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the value of the Trust Units.

The value of the Trust Units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things, the accuracy of the reserves and future production estimated to be attributable to the Trust’s interest in the Underlying Properties. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves is inherently uncertain. Ultimately, actual production and revenues forfrom the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:

·       historical production from the area compared with production rates from other producing areas;

·       the assumed effect of expected governmental regulation and future tax rates.

Changes in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future as a result of future decreases in the price of oil or natural gas.

The reserve report estimating the Trust’s proved reserves, future production and income attributable to the Trust’s interests in the Underlying Properties as of December 31, 20212023 was prepared, in accordance with applicable regulations, using an average of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on December 31, 20212023 as required by the SEC. The applicable prices for 20212023 were $66.56$78.22 per Bbl of oil and $3.598$2.637 per Mcf of natural gas.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices, which could reduce the amount of cash available for distribution to Trust unitholders.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices There can be no assurance that OPEC members and other oil exporting nations willmight not agree to future production cuts or other actions to support and stabilize oil prices, nor can there be any assurance thatand they willmay not further reduce oil prices or increase production.production in the future. Uncertainty regarding future actions to be taken bythat OPEC members or other oil exporting countries may take could lead to a continuation in thecontinued volatility in the price of oil, which could adversely affect the financial condition and economic performance of the operators of the underlying propertiesUnderlying Properties and may reduce the net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders.

Third partyThird-party operators are the operators of all of the wells on the Underlying Properties and, therefore, the Sponsor is not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves on such properties.

As of December 31, 2021,2023, all of the wells on the Underlying Properties were operated by third partythird-party operators. As a result, the Sponsor has limited ability to exercise influence over, and control the risks or costs associated with, the operations of these properties. The failure of a third partythird-party operator to adequately or efficiently perform operations, a third partythird-party operator’s breach of the applicable operating agreements or a third partythird-party operator’s failure to act in ways that are in the Sponsor’s or the Trust’s best interests could reduce production and revenues.revenues and therefore, proceeds payable to the Trust and, ultimately, cash available for distribution to Trust unitholders. Further, none of the third-party operators of the Underlying Properties is obligated to undertake any development activities, so any development and production activities will be subject to their reasonable discretion. TheTherefore, the success and timing of drilling and development activities on properties operated by the third-party operators therefore, dependsdepend on a number of factors that will beare largely outside of the Sponsor’s control, including:

·       the timing and amount of capital expenditures, which could be significantly more than anticipated;

·       the third-party operators’ expertise, operating efficiency and financial resources;

·       approval of other participants in drilling wells;

·       the selection of technology;

·       the selection of counterparties for the sale of production; and

·       the rate of production of the reserves.

The third-party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated fashion, which may result in significant fluctuations in capital expenditures and amounts available for distribution to Trust unitholders.

In addition, disagreements may arise between one or more of the operators, on the one hand, and the Sponsor, on the other hand, regarding the associated costs of the Underlying Properties for which the Sponsor may be responsible, a portion of which may be attributable to the Trust, to the extent of the Trust’s interest in the Underlying Properties. Such disagreements could result in litigation or other legal proceedings, which could reduce cash available for distribution to Trust unitholders.

Developing oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and producing activities could decrease revenues that are available for distribution to Trust unitholders.

The process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous risks beyond the Trust’s,control of the Sponsor’s andTrust, the third party operators’ control,Sponsor or the third-party operators, including risks that could delay the operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production, including:

·       reductions in oil or natural gas prices;

·       delays imposed by or resulting from compliance with regulatory requirements, including permitting;

·       unusual or unexpected geological formations;

·       shortages of or delays in obtaining equipment and qualified personnel;

·       lack of available gathering facilities or delays in construction of gathering facilities;

·       lack of available capacity on interconnecting transmission pipelines;

·       equipment malfunctions, failures or accidents;

·       unexpected operational events and drilling conditions;

·       market limitations for oil or natural gas;

·       pipe or cement failures;

·       casing collapses;

·       lost or damaged drilling and service tools;

·       loss of drilling fluid circulation;

·       uncontrollable flows of oil and natural gas, inert gas, water or drilling fluids;

·       fires and natural disasters;

·       adverse weather conditions; and

·       oil or natural gas property title problems.

If planned operations, including drilling of development wells, are delayed or cancelled, or if existing wells or development wells experience production below anticipated levels due to one or more of the foregoing factors or for any other reason, estimated future distributions to Trust unitholders may be reduced. If an operator incurs increased costs due to one or more of the foregoing factors or for any other reason and is unable to recover such costs from insurance, estimated future distributions to Trust unitholders may be reduced.

Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction inreduce the amount of cash available for distribution to the Trust unitholders.

The demand for qualified and experienced personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically, there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies, equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of the operators of the Underlying Properties to conduct the operations whichthat they currently have planned for the Underlying Properties, which would reduce the amount of cash received by the Trust and available for distribution to the Trust unitholders.

The generationamount of profitscash available for distribution by the Trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.

The amount of oil and natural gas that may be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several months. In many cases, the operators of the Underlying Properties receive only limited notice, if any, as to when production will be curtailed and the duration of such curtailments. If the operators of the Underlying Properties are forced to reduce production due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders similarly would be reduced due to the reduction of profits from the sale of production.

Adverse developments in Texas, Louisiana or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash available for distributionsdistribution to Trust unitholders.

The operations of the Underlying Properties are focused on the production and development of oil and natural gas within the states of Texas, Louisiana and New Mexico. As a result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas. This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in these areas. Due to the lack of diversification in geographic location,diversification, adverse developments in exploration and production of oil and natural gas in any of these areas of operation could have a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more diversified.

FINANCIAL RISKS

The Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties.

Enduro acquired the Underlying Properties through various acquisitions in late 2010 and early 2011. The Sponsor acquired Enduro’s interests in the Underlying Properties pursuant to the Sale Transaction that closed in August 2018. The existence of a material title deficiency with respect to the Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest and the distributions to Trust unitholders. The Sponsor does not obtain title insurance covering mineral leaseholds, and the Sponsor’s failure to cure any title defects may cause the Sponsor to lose its rights to production from the Underlying Properties. If a material title problem were to arise, net profits available for distribution to Trust unitholders, and the value of the Trust Units, may be reduced.

The reserves attributable to the Underlying Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore, proceeds to the Trust and cash distributions to Trust unitholders will decrease over time.

The net profits payable to the Trust attributable to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil and natural gas produced from the Underlying Properties will decline over time.

Future maintenance projects on the Underlying Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Neither the Sponsor nor, to the Sponsor’s knowledge, the third-party operators have a contractual obligation to develop or otherwise pay development expenses on the Underlying Properties in the future. Furthermore, with respect to properties for which the Sponsor is not designated as the operator, the Sponsor has limited control over the timing or amount of those development expenses. The Sponsor also has the right to non-consent and not participate in the development expenses on properties for which it is not the operator, in which case the Sponsor and the Trust will not receive the production resulting from such development expenses. If the operators of the Underlying Properties do not implement maintenance projects when warranted, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Sponsor or estimated in the reserve report.

The Trust Agreement provides that the Trust’s activities are limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance related to the Net Profits Interest. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable to the Net Profits Interest.

Because the net profits payable to the Trust are derived from the sale of depleting assets, the portion of the distributions to Trust unitholders attributable to depletion may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the Trust may, therefore, cease to receive any distributions of net profits therefrom. At that point the value of the Trust Units should be expected to be $0.

An increase in the differential between the price realized by the Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark price of oil or natural gas could reduce the net profits payable to the Trust and, therefore, the cash distributions by the Trust and the value of the Trust Units.

The prices received for the Sponsor’s oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge positions. The difference between the price received and the benchmark price is called a basis differential. The differential may vary significantly due to market conditions, the quality and location of production and other factors. The Sponsor cannot accurately predict oil or natural gas differentials. Increases in the differential between the realized price of oil and natural gas and the benchmark price for oil and natural gas could reduce the profits to the Trust, the cash distributions by the Trust and the value of the Trust Units.

The amount of cash available for distribution by the Trust will be reduced by the amount of anyHigher production and development costs and expenses related to the Underlying Properties and other costs and expenses incurred by the Trust.Trust, without concurrent increases in revenue, will reduce the amount of cash available for distribution to Trust unitholders.

The Trust will indirectly bearbears an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating and development expenses, which will reducereduces the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Accordingly, higher costs and expenses related to the Underlying Properties will directly decrease the amount of cash received by the Trust in respect of its Net Profits Interest. Historical costs may not be indicative of future costs. For example, the third-party operators may in the future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying Properties, which could reduce cash available for distribution by the Trust. In addition, cash available for distribution by the Trust will be further reduced by the Trust’s general and administrative expenses.

If direct operating and development expenses on the Underlying Properties, together with the other costs, exceed gross profits of production from the Underlying Properties, the Trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess costs, plus accrued interest at the prime rate. If the Trust does not receive net profits pursuant to the Net Profits Interest, or if such net profits are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.

The Trust has established a cash reserve for contingent liabilities and to pay expenses in accordance with the Trust Agreement, which would reduce net profits payable to the Trust and distributions to Trust unitholders.

The Trust’s source of capital is the cash flows from the Net Profits Interest. Pursuant to the Trust Agreement, the Trust may establish a cash reserve through the withholding of cash for contingent liabilities and to pay expenses, which will reduce the amount of cash otherwise available for distribution to Trust unitholders.

In November 2021, the Trustee notified the Sponsor thatof the Trustee intendsTrustee’s intent to build a cash reserve for the payment of future known, anticipated or contingent expenses or liabilities. Commencingliabilities of the Trust. From February 2022 through March 2023, the Trustee withheld $37,833, and commencing with the distribution paid to Trust unitholders paid in February 2022, the Trustee isApril 2023 has been withholding and, in the future, intends to withhold $37,833$50,000, from the funds otherwise available for distribution each month to gradually build a cash reserve of approximately $2.3 million. ThisAs of December 31, 2023, the cumulative cash is reserved for the payment of future known, anticipated or contingent expenses or liabilities of the Trust.reserve balance was $941,386. The Trustee may increase or decrease the targeted amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash reserve at any time, without advance notice to the Trust unitholders.

The amount of cash available for distribution by the Trust could be reduced by expenses caused by uninsured claims.

The Sponsor maintains insurance coverage against potential losses that it believes is customary in its industry. The SponsorCOERT currently maintains general liability insurance and excess liability coverage. The Sponsor’s excess liability coverage and general liability insurance do not have deductibles. The general liability insurance covers the Sponsor and its subsidiaries for legal and contractual liabilities arising out of bodily injury or property damage, including any resulting loss of use to third parties, and for sudden and accidental pollution or environmental liability, while the excess liability coverage is in addition to and triggered if the general liability per occurrence limit is reached. In addition, the Sponsor maintains control of well insurance with per occurrence limits depending on the status of the well and deductibles consistent with industry standards. The Sponsor’s general liability insurance and excess liability policies do not provide coverage with respect to legal and contractual liabilities of the Trust, and the Trust does not maintain such coverage since it is passive in nature and does not have any ability to influence the Sponsor or control the operations or development of the Underlying Properties. However, the Trust unitholders may indirectly benefit from the Sponsor’s insurance coverage to the extent that insurance proceeds offset or reduce any costs or expenses that are deducted when calculating the net profits attributable to the Trust.

The Sponsor does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, the Sponsor believesoperations, other than its general liability and excess liability insurance policies wouldthat may cover third-party claims related to hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related to government-mandated cleanup of pollution. In addition, these policies do not provide coverage for all liabilities, and there can be no assurance that the insurance coverage willmay not be adequate to cover claims that may arise or thatarise; moreover, the Sponsor willmay not be able to maintain adequate insurance at rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution by the Trust. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration and production, hydraulic fracturing operations, or related activities.

The Sponsor’s ability to perform its obligations to the Trust could be limited by restrictions under its debt agreements.

The Sponsor has various contractual obligations to the Trust under the Trust Agreement and Conveyance. Restrictions under the Sponsor’s debt agreements, including certain covenants, financial ratios and tests, could impair its ability to fulfill its obligations to the Trust. The requirement that the Sponsor comply with these restrictive covenants and financial ratios and tests may materially adversely affect its ability to react to changes in market conditions, take advantage of business opportunities it believes to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in its business which may, in turn, impair the Sponsor’s operations and its ability to perform its obligations to the Trust under the Trust Agreement and Conveyance. If the Sponsor is unable to perform its obligations to the Trust under the Trust Agreement or Conveyance, it could have a material adverse effect on the Trust.

The bankruptcy of the Sponsor or any of the third-party operators could impede the operation of the wells and the development of the proved undeveloped reserves.

The value of the Net Profits Interest and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of the operators of the Underlying Properties. None of the operators of the Underlying Properties, including the Sponsor, has agreed with the Trust to maintain a certain net worth or to be restricted by other similar covenants.

The ability to develop and operate the Underlying Properties depends on the future financial condition and economic performance and access to capital of the operators of those properties, which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control of the Sponsor and the third party operators. If the reducedReduced demand for crude oil in the global market as a result of the economic effects of the COVID-19 pandemic persists for the near future or longer, such factors could have a negative impact on the financial condition and economic performance of one or more of the operators of the Underlying Properties. The Sponsor is not a reporting company and is not required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, Trust unitholders do not have access to financial information about the Sponsor.

In the event of any future bankruptcy of any operator of the Underlying Properties, the working interest owners in the affected properties will have to seek a new party to perform the development and the operations of the affected wells. The working interest owners may not be able to find a replacement driller or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable period. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to Trust unitholders, and could adversely affect the value of the Net Profits Interest.

In the event of the bankruptcy of the Sponsor, if a court were to hold that the Net Profits Interest was part of the bankruptcy estate, the Trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.

The Sponsor and the Trust believe that, in a bankruptcy of the Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of the Sponsor’s bankruptcy estate. However, if the bankruptcy court were to the extent that were not the case,hold otherwise, or to the extentif Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors of the Sponsor, in which case the Trust would be an unsecured creditor of the Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors.

RISKS RELATED TO THE STRUCTURE OF THE TRUST

The Trust is passive in nature and neither the TrustTrustee nor the Trust unitholders have any ability to influence the Sponsor or control the operations or development of the Underlying Properties.

The Trust Units are a passive investment that entitles the Trust unitholderunitholders to only receive cash distributions derived from the Net Profits Interest. Trust unitholders have no voting rights with respect to the Sponsor and, therefore, have no managerial, contractual or other ability to influence the Sponsor’s or the third-party operators’ activities or the operations of the Underlying Properties. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. Third party operators operate substantially all of the wells on the Underlying Properties. The typical operating agreement contains procedures whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property. Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale of production, compliance with regulatory requirements and other matters that affect the property. Neither the Trustee nor the Trust unitholders have any contractual ability to influence or control the field operations of, sale of oil or natural gas from, or any future development of, the Underlying Properties. The current operators developing the Underlying Properties are under no obligations to continue operations on the Underlying Properties. Neither the Trustee nor the Trust unitholders have the right to replace an operator.

TheSubject to specified limitations, the Sponsor may transfer all or a portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.consent.

The Sponsor at any time may transfer all or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may, along with the third-party operators, abandon individual wells or properties reasonably believed to be not economically viable. Trust unitholders will not be entitled to vote on any transfer or abandonment of the Underlying Properties, and the Trust will not receive any profitsnet proceeds from any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer, in which case the Trust will receive an amount equal to the fair market value (net of sales costs) of the Net Profits Interest released. Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection with such sale or transfer, the Net Profits Interest will continue to burden the transferred property and net profits attributable to such property will be calculated as part of the computation of net profits. The Sponsor may delegate to the transferee responsibility for all of the Sponsor’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred.

In addition, the Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with any lease that accounts for no more than 0.25% or less of the total production from the Underlying Properties in the prior 12 months, and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000. These releases willmay be made only in connection with a sale by the Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair market value of such Net Profits Interest being treated as an offset amount against costs and expenses. In September 2021,For example, in May 2023, the Sponsor entered into a lease arrangement with respectsold approximately $0.3 million in non-producing, non-cash flowing acreage to a portionprivate oil company, free and clear of the mineral rights relating to certain ofNet Profits Interest, as permitted under the Underlying Properties located in Borden County, Texas, for total estimatedTrust Agreement. The proceeds of $82,500 (approximately $63,000 netfrom this sale attributable to the Trust’s 80% Net Profits Interest).Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

The third-party operators and the Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval of the Trustee or any Trust unitholder.

Under certain circumstances, the Trustee must sell the Net Profits Interest and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders may not recover their investment.

The Trustee must sell the Net Profits Interest and dissolve the Trust if the holders of at least 75% of the outstanding Trust Units approve the sale or vote to dissolve the Trust. The Trustee must also sell the Net Profits Interest and dissolve the Trust if the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of any two consecutive years. The net profits of any such sale will be distributed to the Trust unitholders.

Conflicts of interest could arise between the Sponsor and its affiliates, on the one hand, and the Trust and the Trust unitholders, on the other hand.

As working interest owners in, and the operators of certain wells on, the Underlying Properties, the Sponsor and its affiliates could have interests that conflict with the interests of the Trust and the Trust unitholders. For example:

The Trust is administered by a Trustee who cannot be replaced except by a majority vote of the Trust unitholders at a special meeting, which may make it difficult for Trust unitholders to remove or replace the Trustee.

The affairs of the Trust are administered by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the Trust Units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust Units held by the Sponsor, called by either the Trustee or the holders of not less than 10% of the outstanding Trust Units. As a result, it will be difficult for public Trust unitholders to remove or replace the Trustee without the cooperation of holders of a significant percentage of total Trust Units.

Trust unitholders have limited ability to enforce provisions of the Net Profits Interest,Conveyance, and the Sponsor’s liability to the Trust is limited.

The Trust Agreement permits the Trustee to sue the Sponsor or any other future owner of the Underlying Properties to enforce the terms of the Conveyance creating the Net Profits Interest.Conveyance. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, Trust unitholders’ recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust Agreement expressly limits a Trust unitholder’s ability to directly sue the Sponsor or any other third party other than the Trustee. As a result, Trust unitholders will not be able to sue the Sponsor or any future owner of the Underlying Properties to enforce these rights. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, the Sponsor will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without gross negligence or willful misconduct. In addition, the Trust Agreement provides that, to the fullest extent permitted by law, the Sponsor is not subject to fiduciary duties or liable for conflicts of interest principles.

Financial information of the Trust is not prepared in accordance with GAAP.

The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the SEC, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production, expenses are recorded when paid and not when incurred, and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.

The Trust is a smaller reporting company and benefits from certain reduced governance and disclosure requirements, including that the Trust’s independent registered public accounting firm is not required to attest to the effectiveness of the Trust’s internal control over financial reporting. The Trust cannot be certain if the omission of reduced disclosure requirements applicable to smaller reporting companies will make the Trust Units less attractive to investors.

Currently, the Trust is a “smaller reporting company,” meaning that the outstanding Trust Units held by nonaffiliates had a value of less than $250 million at the end of the Trust’s most recently completed second fiscal quarter. As a smaller reporting company, the Trust is not required to comply with the auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, meaning the Trust’s auditors are not required to attest to the effectiveness of the Trust’s internal control over financial reporting. As a result, investors and others may be less comfortable with the effectiveness of the Trust’s internal controls and the risk that material weaknesses or other deficiencies in internal controls go undetected may increase. In addition, as a smaller reporting company, the Trust takes advantage of its ability to provide certain other less comprehensive disclosures in its SEC filings, including, among other things, providing only two years of audited financial statements in annual reports. Consequently, it may be more challenging for investors to analyze the Trust’s results of operations and financial prospects, as the information the Trust provides to Trust unitholders may be different from what one might receive from other public companies in which one holds shares. As a smaller reporting company, the Trust is not required to provide this information.

RISKS RELATED TO OWNERSHIP OF THE TRUST UNITS

If the Trust cannot meet the New York Stock Exchange continued listing requirements, the NYSE may delist the Trust Units.

Under the continued listing requirements of the NYSE, a company will be considered to be out of compliance with the exchange’s minimum price requirement if the company’s average closing price over a consecutive 30 trading day period (“Average Closing Price”) is less than $1.00 (the “Minimum Price Requirement”).  Under NYSE rules, a company that is out of compliance with the Minimum Price Requirement has a cure period of six months to regain compliance if it notifies the NYSE within 10 business days of receiving a deficiency notice of its intention to cure the deficiency. A company may regain compliance if on the last trading day of any calendar month during the cure period the company has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30-trading-day period ending on the last trading day of that month. If at the expiration of the cure period, both a $1.00 closing share price on the last trading day of the cure period and a $1.00 average closing share price over the 30-trading-day period ending on the last trading day of the cure period are not attained, the NYSE will commence suspension and delisting procedures. If delisted by the NYSE, a company’s shares may be transferred to the over-the-counter (“OTC”) market, a significantly more limited market than the NYSE, which could affect the market price, trading volume, liquidity and resale price of such shares. Securities that trade on the OTC markets also typically experience more volatility compared to securities that trade on a national securities exchange. During the cure period, the company’s shares would continue to trade on the NYSE, subject to compliance with other continued listing requirements.

On September 25, 2020, the The Trust received written notification from the NYSE that the Trust was not in compliance with the Minimum Price Requirement. Neither the Trust nor the Trustee has any control over the trading pricefallen out of the Trust Units, nor does the Trust have the authority to cause a reverse split of the units or to take similar action designed to affect the trading price of the units without a vote from the Trust unitholders. Although the NYSE notified the Trust that the Trust had regained compliance with the Minimum Price Requirement as of February 26, 2021, it mightin the past, most recently in 2020, and although the Trust was able to regain compliance within the applicable grace period, the Trust may be unable to maintain compliance in the future and wouldcould again become subject to the NYSE delisting procedures. Over the 30-day trading period that ended March 20, 2024, the closing price of the Trust Units on the NYSE ranged from a high of $1.68 on February 8, 2024 to a low of $1.33 on March 20, 2024.