Permianville Royalty Trust - Annual Report: 2019 (Form 10-K)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the fiscal year ended December 31, 2019

or

For the transition period from                      to                     

Commission File Number 001-35333

PERMIANVILLE ROYALTY TRUST

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: 1-512-236-6555

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of class)

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ¨    No  x.

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  x.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes   x     No   ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes   ¨     No   ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).    Yes  ¨    No  x

The aggregate market value of the voting and non-voting common equity held by non-affiliates (24,400,000 Units of Beneficial Interest) computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $64,904,000.

As of March 9, 2020, 33,000,000 Units of Beneficial Interest of the Trust were outstanding.

Documents Incorporated By Reference: None

TABLE OF CONTENTS

References to the “Trust” in this document refer to Permianville Royalty Trust, while references to “COERT” or “the Sponsor” in this document refer to COERT Holdings 1, LLC.

FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K includes (this “Form 10-K”) “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical fact included in this Form 10-K, including without limitation the statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” and “Risk Factors,” regarding the financial position, business strategy, production and reserve growth, and other plans and objectives for the future operations of the Sponsor and regarding future matters relating to the Trust are forward-looking statements. Such statements may be influenced by factors that could cause actual outcomes and results to differ materially from those projected. No assurance can be given that such expectations will prove to have been correct. When used in this document, the words “believes,” “expects,” “anticipates,” “intends” or similar expressions are intended to identify such forward-looking statements. The following important factors, in addition to those discussed elsewhere in this Form 10-K, could affect the future results of the energy industry in general, and the Sponsor and the Trust in particular, and could cause actual results to differ materially from those expressed in such forward-looking statements:

Unitholders should not place undue reliance on these forward-looking statements. All forward-looking statements speak only as of the date of this Form 10-K. The Trust does not undertake any obligation to release publicly any revisions to the forward-looking statements to reflect events or circumstances after the date of this Form 10-K or to reflect the occurrence of unanticipated events, unless the securities laws require the Trust to do so.

This Form 10-K describes other important factors that could cause actual results to differ materially from expectations of the Sponsor and the Trust, including under the caption “Risk Factors.” All subsequent written and oral forward-looking statements attributable to the Sponsor or the Trust or persons acting on behalf of the Sponsor or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these forward-looking statements.

GLOSSARY OF CERTAIN OIL AND NATURAL GAS TERMS

In this Form 10-K the following terms have the meanings specified below.

Bbl—One barrel of 42 U.S. gallons liquid volume, used herein in reference to crude oil and other liquid hydrocarbons.

Boe—One barrel of oil equivalent, computed on an approximate energy equivalent basis that one Bbl of crude oil equals approximately six Mcf of natural gas.

Btu—A British Thermal Unit, a common unit of energy measurement.

Completion—The installation of permanent equipment for the production of oil or natural gas, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Development Well—A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Differential—The difference between a benchmark price of oil and natural gas, such as the NYMEX crude oil spot, and the wellhead price received.

Estimated future net revenues—Also referred to as “estimated future net cash flows.” The result of applying current prices of oil and natural gas to estimated future production from oil and natural gas proved reserves, reduced by estimated future expenditures, based on current costs to be incurred, in developing and producing the proved reserves, excluding overhead.

Farm-in or farm-out agreement—An agreement under which the owner of a working interest in an oil or natural gas lease typically assigns the working interest or a portion of the working interest to another party who desires to drill on the leased acreage. Generally, the assignee is required to drill one or more wells in order to earn its interest in the acreage. The assignor usually retains a royalty or reversionary interest in the lease. The interest received by an assignee is a “farm-in” while the interest transferred by the assignor is a “farm-out.”

Field—An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

GAAP—Accounting principles generally accepted in the United States of America.

Gross acres or gross wells—The total acres or wells, as the case may be, in which a working interest is owned.

MBbl—One thousand barrels of crude oil or condensate.

MBoe—One thousand barrels of oil equivalent.

Mcf—One thousand cubic feet of natural gas.

MMBoe—One million barrels of oil equivalent.

MMBtu—One million British Thermal Units.

MMcf—One million cubic feet of natural gas.

Net acres or net wells—The sum of the fractional working interests owned in gross acres or wells, as the case may be.

Net profits interest—A nonoperating interest that creates a share in gross production from an operating or working interest in oil and natural gas properties. The share is measured by net profits from the sale of production after deducting costs associated with that production.

Net revenue interest—An interest in all oil and natural gas produced and saved from, or attributable to, a particular property, net of all royalties, overriding royalties, Net Profits Interests, carried interests, reversionary interests and any other burdens to which the interest is subject.

Plugging and abandonment—Activities to remove production equipment and seal off a well at the end of a well’s economic life.

Proved developed reserves—Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves—Under SEC rules, proved reserves are defined as:

Those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The area of the reservoir considered as proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons, LKH, as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. Where direct observation from well penetrations has defined a highest known oil, HKO, elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (ii) the project has been approved for development by all necessary parties and entities, including governmental entities. Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Proved undeveloped reserves—Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

PV-10— A non-GAAP financial measure of the present value of estimated future net revenues to be generated from the production of proved reserves, net of estimated future production and development costs, using prices and costs as of the date of estimation without future escalation, without giving effect to income taxes, discounted at 10% per annum.

Recompletion—The completion for production of an existing wellbore in another formation from which that well has been previously completed.

Reservoir—A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.

Working interest—The right granted to the lessee of a property to explore for and to produce and own oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.

Workover—Operations on a producing well to restore or increase production.

PART I

Permianville Royalty Trust (the “Trust”), previously known as Enduro Royalty Trust, is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying Properties.”

In connection with the closing of the initial public offering of units of beneficial interest in the Trust (“Trust Units”) in November 2011, Enduro Operating LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro Operating”), and Enduro Texas LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro Texas”), merged, with each entity surviving the merger. By virtue of the merger, Enduro Texas retained all rights, title and interest to the Net Profits Interest. Enduro Operating and Enduro Texas entered into a Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (as supplemented and amended to date, the “Conveyance”), to effect the transfer of the Net Profits Interest from Enduro Operating to Enduro Texas.

On November 8, 2011, Enduro Texas merged with and into the Trust (the “Trust Merger”) pursuant to an Agreement and Plan of Merger dated November 3, 2011 (the “Trust Merger Agreement”). Under the terms of the Trust Merger Agreement, the Trust continued as the surviving entity, and the limited liability company interest in Enduro Texas held by Enduro prior to the effective time of the Trust Merger converted into the right to receive 33,000,000 Trust Units. Further, by virtue of the Trust Merger, the Trust retained all right, title and interest to the Net Profits Interest (including the right to enforce the Conveyance against Enduro Operating, as grantor). On November 8, 2011, the Trust, Enduro Operating and Enduro Texas entered into a Supplement to Conveyance of Net Profits Interest to acknowledge that The Bank of New York Mellon Trust Company, N.A., as Trustee, is deemed the grantee under the Conveyance and a party thereto.

Immediately following the Trust Merger, Enduro completed an initial public offering of 13,200,000 Trust Units at a price to the public of $22 per unit.

In October 2013, Enduro completed a secondary offering of 11,200,000 Trust Units at a price to the public of $13.85 per unit. The Trust did not sell any Trust Units in the offering and did not receive any proceeds from the offering. After the completion of the secondary offering, Enduro owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.

At a special meeting of Trust unitholders held on August 30, 2017, unitholders approved several proposals, including amendments to the Trust Agreement and Conveyance. In September 2017, 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 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 75% to 50% of the outstanding units of the Trust. To effect the same changes as those included in the amended Trust Agreement, Enduro, the Trustee and the Delaware Trustee also entered into the First Amendment to Conveyance of Net Profits Interest. As a result of the Trust unitholders approving amendments to the Trust Agreement and Conveyance and the approval of the divestiture of certain properties in the Permian Basin, Enduro and the Trustee entered into the Partial Release, Reconveyance and Termination Agreement (the “Partial Release”). Pursuant to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated and released to Enduro the Net Profits Interest with respect to certain of the Underlying Properties sold pursuant to eight letter agreements or purchase and sale agreements, as applicable, entered into between Enduro and eight separate counterparties.

In July 2018, Enduro entered into a purchase and sale agreement with COERT Holdings 1 LLC (“COERT” or the “Sponsor”) for the Underlying Properties and all of the outstanding Trust Units owned by Enduro (the “Sale Transaction”), and on August 31, 2018, the parties closed the Sale Transaction. In connection with the Sale Transaction, COERT assumed all of Enduro’s obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were parties. COERT is a Delaware limited liability company engaged in the production and development of oil and natural gas from properties located in the Rockies, the Permian Basin of west Texas and southeastern New Mexico, and the Arklatex region of Texas and Louisiana.

References to “COERT” or the “Sponsor” in this Form 10-K refer to COERT Holdings 1 LLC, the current sponsor of the Trust, and references to “Enduro” in this Form 10-K refer to Enduro Resource Partners LLC, the original sponsor of the Trust.

The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production from the Underlying Properties during the term of the Trust. The Trust Agreement provides that the Trust’s business 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. As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.

The Trust has no employees. Administrative functions are performed by the Trustee pursuant to the Trust Agreement. The Trustee has no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities on the Underlying Properties. The duties of the Trustee are specified in the Trust Agreement and by the laws of the state of Delaware, except as modified by the Trust Agreement. The Trustee’s principal duties consist of:

In connection with the formation of the Trust, the Trust entered into several agreements with Enduro that imposed obligations upon Enduro, including the Conveyance and a Registration Rights Agreement, which COERT assumed in connection with the Sale Transaction. The Trustee has the power and authority under the Trust Agreement to enforce these agreements on behalf of the Trust. Additionally, the Trustee may from time to time supplement or amend the Conveyance and the Registration Rights Agreement without the approval of Trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant any benefit to all of the Trust unitholders, to comply with changes in applicable law or to change the name of the Trust. Such supplement or amendment, however, may not materially adversely affect the interests of the Trust unitholders.

The Trustee may create a cash reserve to pay for future liabilities of the Trust and may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves. The Trustee may authorize the Trust to borrow from any person, including the Trustee, the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee nor any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were loaned by the Trustee, Delaware Trustee or an affiliate thereof, would be similar to the terms that such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. Under the terms of the Trust Agreement, COERT has provided the Trust with a $1.2 million letter of credit to be used by the Trust in the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses. If the Trust requires more than the $1.2 million under the letter of credit to pay administrative expenses, COERT has agreed to loan funds to the Trust necessary to pay such expenses. If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid.  The total amount drawn of $34,818 will be recouped from the subsequent distribution April 2020 as a reduction of NPI income received from the Sponsor.  

Each month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds received from the Net Profits Interest. The cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be held in a noninterest-bearing account or may be invested in: 

The Trust is not subject to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time. The Trust will dissolve upon the earliest to occur of the following:

Upon dissolution of the Trust, the Trustee would sell all of the Trust’s assets, either by private sale or public auction, and, after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.

Marketing and Post-Production Services

Pursuant to the terms of the Conveyance, the Sponsor has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest in the Underlying Properties. The terms of the Conveyance restrict the Sponsor from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to non-affiliates. Accordingly, a marketing fee is not deducted (other than fees paid to non-affiliates) in the calculation of the Net Profits Interest’s share of net profits. The net profits to the Trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interest is determined based on the same price that the Sponsor receives for sales of oil and natural gas production attributable to the Sponsor’s interest in the Underlying Properties. However, if the oil or natural gas is processed, the net profits receive the same processing upgrade or downgrade as the Sponsor.

The operators of the Underlying Properties sell the oil produced from the Underlying Properties to third-party crude oil purchasers. Oil production from the Underlying Properties is typically transported by truck from the field to the closest gathering facility or refinery. The operators sell the majority of the oil production from the Underlying Properties under contracts using market sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon delivery location and oil quality. Natural gas produced by the operators is marketed and sold to third-party purchasers. The natural gas is sold pursuant to contracts with such third parties, and the sales contracts are in their secondary terms and are on a month-to-month basis. The contract prices are based on a published regional index price, after adjustments for Btu content, transportation and related charges.

The following purchasers individually accounted for ten percent or more of sales from the Underlying Properties that were included in calculating the Trust’s “Income from net profits interest” for the periods presented. The table provides the percentage represented by the purchasers during the periods presented:

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 of 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 9, 2020.

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 that 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 are responsible for all costs associated with calling such meeting. Meetings must be held in such location as is designated by the Trustee 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 to have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned. Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the Trust Agreement, 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 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 the special meeting of Trust unitholders held on August 30, 2017, unitholders approved amendments to the Trust Agreement. In September 2017, 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 75% to 50% of the outstanding units of the Trust.

In addition, 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 for 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 that 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 Interest and payments of expenses incurred. 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 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 less 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 January 2019, the Sponsor sold two producing wells and associated acreage of the Underlying Properties under this provision for a sale price of approximately $62,000, and the Trustee released such properties from the Net Profits Interest.

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 for the Net Profits Interest to the Trust. 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 gains (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. While the Trump Administration has 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,” 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 responsible for the release of a “hazardous substance” into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances released at the site. These responsible persons may be subject to joint and several strict liability 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. The Sponsor generates materials in the course of its operations that may be regulated as hazardous substances.

The Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. 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 RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas 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 into 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 wastes 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. 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 gas wastes are not necessary, along 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.

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, petroleum 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 recycling 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 the petroleum hydrocarbons and wastes disposed or released at or from these properties may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Sponsor could be required to remove or remediate previously disposed wastes, to clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells to prevent future contamination or to pay some or all of the costs of any such action.

Water discharges. The Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil, into federal and state waters. The discharge of pollutants into “waters of the United States” is prohibited, except in accordance with the terms of a permit issued by EPA and/or an analogous state agency. The term “waters of the United States” has been broadly defined to include certain inland water bodies, including certain wetlands and intermittent streams. The discharge of dredge and fill material in regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (“ACE”). CWA Section 401 provides that the applicant for an individual National Pollutant Discharge Elimination System (“NPDES”) permit to be issued by the EPA or an individual Section 404 permit to be issued by the ACE must notify 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 ACE define “waters of the United States” (“WOTUS”) can impact the Sponsor’s regulatory and permitting obligations under the CWA. The EPA and the ACE promulgated rules defining the scope of WOTUS that became effective in September 2015. On October 22, 2019, the EPA and the ACE published a final rule that repealed the 2015 definition of WOTUS and recodified longstanding regulatory definitions of WOTUS that existed prior to the 2015 rule to promote regulatory consistency across the United States. On February 14, 2019, the EPA and the ACE had published a proposed revised definition of WOTUS intended to clarify and narrow the definition from that in the 2015 rule. The comment period on the proposed changes to the definition of WOTUS closed on April 15, 2019, and a final rule is expected to be published in early 2020. It is anticipated that petitions for review of any 2020 WOTUS rule will be filed and that litigation over the definition of WOTUS will continue. To the extent that the Sponsor must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other waters of the United States, The Sponsor could face increased costs and delays associated with obtaining such permits under any broader definition of WOTUS that expands the scope of CWA jurisdiction.

Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. Spill prevention, control and countermeasure (“SPCC”) plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of waters of the United States in the event of a hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws required individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. In June 2016, the EPA issued a final rule implementing wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater directly to publicly owned treatment works (“POTWs”). Unconventional oil and gas extraction facilities can send wastewater to a private wastewater treatment facility that can either discharge treated wastewater or send it to a POTW. The EPA is conducting a related study of treatment of oil and gas extraction wastewater at private wastewater treatment facilities. This restriction of disposal options for hydraulic fracturing waste and other changes to CWA requirements may result in increased costs to the Sponsor. In addition, naturally occurring radioactive material (“NORM”) is brought to the surface in connection with oil and gas production. Concerns have arisen over traditional NORM disposal practices (including discharge through publicly owned treatment works into surface waters), which may increase the costs associated with management of NORM.

The Oil Pollution Act of 1990, as amended, or OPA, amends the CWA and establishes strict liability and natural resource damages liability for unauthorized discharges of oil into waters of the United States. OPA requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.

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-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 our operations at this time by requiring new air emissions controls, equipment modification, maintenance, monitoring, recordkeeping and reporting. Although these new requirements will increase our operating and capital expenditures and it is possible that the EPA will adopt further regulation that could further increase our operating and capital expenditures, we do not currently expect such existing and new regulations will have a material adverse impact on our 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 and also 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. No assurance can be given as to whether or not similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located.

Air emissions. The federal Clean Air Act (“CAA”) and comparable state laws restrict the emission of air pollutants from many sources through air emissions permitting and regulatory programs 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, obtain and strictly comply with stringent air emissions permit requirements or incur development expenses to install and utilize specific equipment or technologies to control emissions. For example, the EPA in 2012 adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound 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, and from pneumatic controllers and storage vessels. In June 2016, the EPA published a final rule adopting additional NSPS requirements for new, modified, or reconstructed oil and gas facilities that require control of the greenhouse gas methane from affected facilities, including requirements to find and repair fugitive leaks of methane emissions at well sites (“Methane Rule”). Following the 2016 presidential election and change in administrations, in 2017 the EPA convened a reconsideration proceeding that culminated in a 2019 rule proposal that would eliminate 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. The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations, which could reduce the profits available to the Trust and potentially impair the economic development of the Underlying Properties. Obtaining permits has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies may impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the federal CAA and associated state laws and regulations.

Climate change. Recent scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” or “GHGs,” and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere. In response to the scientific studies, international negotiations to address climate change have occurred. In December 2015, the United States participated in the 21^st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The Paris Agreement (adopted at the conference) calls for nations to undertake efforts with respect to global temperatures and GHG emissions. If ratified, the Paris Agreement will take effect in 2020. The United States ratified the Paris Agreement in September 2016; however, the country’s future participation in the Paris Agreement is uncertain. In June 2017, President Trump announced that the United States would withdraw from the Paris Agreement, and the United States formally notified the United Nations that it is withdrawing from the Paris Agreement in November 2019, triggering a one-year waiting period prior to final withdrawal. Whether the United States may reenter the Paris Agreement or a separately negotiated agreement is unclear at this time. Further, several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as a result of the Paris Agreement. The adoption and implementation of any laws or regulations imposing reporting obligations on, or limiting emissions of GHGs from operations could require additional expenditures to reduce emissions of GHGs associated with operations or could adversely affect demand for the oil, natural gas and NGL production attributable to the Net Profits Interest, and thus possibly have a material adverse effect on the Trust’s revenues. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, to the extent 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, such events could have an adverse effect on assets and operations related to the Underlying Properties.

Both houses of Congress have actively considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These allowances would be expected to escalate significantly in cost over time. Although it is not possible at this time to predict when Congress may pass climate change legislation, any future federal or state laws that may be adopted to address GHG emissions could require the Sponsor to incur increased operating costs and could adversely affect demand for the oil and natural gas the Sponsor produces.

The EPA has also taken regulatory action aimed at reducing GHG emissions. In December 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment, which has allowed the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the federal Clean Air Act. For example, the EPA adopted regulations under Prevention of Significant Deterioration (“PSD”) and Title V permitting programs for GHG emissions from certain large stationary sources. In June 2014, the U.S. Supreme Court held that GHG emissions alone cannot trigger an obligation to obtain a federal air permit, but the Court upheld EPA’s authority to regulate GHG emissions from major stationary sources where emissions of traditional criteria pollutants exceed federal permitting thresholds. In November 2010, the EPA published its final rule expanding the existing GHG monitoring and reporting rule to include onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. These requirements became applicable in 2012 for emissions occurring in 2011. The Underlying Properties may be subject to these requirements or become subject to them in the future. Meanwhile, as noted above, in June 2016 the EPA finalized the Methane Rule. Following the 2016 presidential election and change in administrations, however, the EPA convened a reconsideration proceeding that that culminated in a 2019 rule proposal that would eliminate 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. Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations. In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands that are substantially similar to the EPA’s Methane Rule. However, in December 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule. Although the future implementation of the EPA and BLM rules aimed at controlling GHG emissions from oil and natural gas sources remains uncertain, future federal GHG regulations for the oil and gas industry remain a possibility given the long-term trend towards increasing regulation.

Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the Sponsor’s operations. In addition to these regulatory developments, recent judicial decisions that have allowed certain tort claims alleging property damage to proceed against GHG emissions sources may increase the Sponsor’s litigation risk for such claims. The adoption of any future regulations that require reporting of GHGs or otherwise limit emissions of GHGs from the equipment and operations of the Sponsor could require the Sponsor to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with its operations, and such requirements also could adversely affect demand for the oil and natural gas that the Sponsor 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 greenhouse gas emitting energy sources, the Sponsor’s products would become more desirable in the market with more stringent limitations on greenhouse gas emissions. In August 2015, the EPA issued standards designed to limit GHG emissions from new power plants as well as the Clean Power Plan aimed at reducing GHG emissions from existing power plants. In February 2016, the U.S. Supreme Court stayed the implementation of the Clean Power Plan pending judicial review, and President Trump has been vocal in opposition to the Clean Power Plan. In October 2017, following a review directed by President Trump’s Energy Independence Executive Order, the EPA proposed to repeal the Clean Power Plan regulations. To the extent that its products are competing with lower greenhouse gas emitting energy, the Sponsor’s products would 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, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced by the Sponsor or otherwise cause the Sponsor to incur significant costs in preparing for or responding to those effects.

National Environmental Policy Act. Oil and natural gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the Department of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay the development of oil and natural gas projects.

Endangered Species Act. The federal Endangered Species Act and similar state statutes restrict activities that may affect endangered and threatened species or their habitats. The presence of endangered species or designation of previously unidentified endangered or threatened species could cause the Sponsor to incur additional costs or become subject to operating delays, restrictions or bans in the affected areas.

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 (“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.

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

Crude oil prices have declined sharply in the first quarter of 2020 in response to the economic effects of the coronavirus pandemic and the recent announcement of planned production increases by Saudi Arabia. Continued low oil and natural gas prices will reduce profits to which the Trust is entitled, which will reduce the amount of each available for distribution to unitholders, and 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.

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 is subject to the possibility of greater fluctuations due to changes in oil and natural gas prices.

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 for 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:

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, 2019 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, 2019 as required by the SEC. The applicable prices for 2019 were $55.69 per Bbl of oil and $2.58 per Mcf of natural gas.

Third party operators are the operators of substantially 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, 2019, substantially all of the wells on the Underlying Properties were operated by third 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 party operator to adequately or efficiently perform operations, a third party operator’s breach of the applicable operating agreements or a third 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. 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. The success and timing of drilling and development activities on properties operated by the third party operators, therefore, depends on a number of factors that will be largely outside of the Sponsor’s control, including:

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.

The bankruptcy of operators could impede the operation of wells.

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 wells. The ability to operate the Underlying Properties depends on all operators’ future financial condition and economic performance and access to capital, 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 such operators. If the reduced demand for crude oil in the global market as a result of the economic effects of the outbreak of coronavirus, and the recent reduction in the benchmark price of crude oil, persist 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.

In the event of any future bankruptcy of any operator of the Underlying Properties, the value of the Net Profits Interest could be adversely affected by, among other things, delay or cessation of payments under the Net Profits Interest, business disruptions or cessation of operations by the operator, replacements of operators, inability to find a replacement operator if necessary, reduced production of reserves, or decreased distributions 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, the Sponsor’s and the third party operators’ control, 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:

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.

The Trust is passive in nature and neither the Trust 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 unitholder to only receive cash distributions 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.

Shortages of equipment, services and qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in 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 which 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 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, profits available for distribution to Trust unitholders, and the value of the Trust Units, may be reduced.

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

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 profits 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 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 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 market value of such Net Profits Interest being treated as an offset amount against costs and expenses. In January 2019, the Sponsor sold two producing wells and associated acreage of the Underlying Properties under this provision for a sale price of approximately $62,000, and the Trustee released such properties from the Net Profits Interest.

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.

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 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 profits to the Trust and, therefore, the cash distributions by the Trust and the value of 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 any costs and expenses related to the Underlying Properties and other costs and expenses incurred by the Trust.

The Trust will indirectly bear an 80% share of all costs and expenses related to the Underlying Properties, such as direct operating and development expenses, which will reduce 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 generation of profits 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.

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.

The Sponsor may sell Trust Units in the public or private markets, and such sales could have an adverse impact on the trading price of the Trust Units.

The Sponsor holds an aggregate of 8,600,000 Trust Units. The Sponsor may sell Trust Units in the public or private markets, and any such sales could have an adverse impact on the price of the Trust Units. The Trust has granted registration rights to the Sponsor, which, if exercised, would facilitate sales of Trust Units by the Sponsor.

The trading price for the Trust Units may not reflect the value of the Net Profits Interest held by the Trust.

The trading price for publicly traded securities similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development expenses. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would realize if it sold the Net Profits Interest to a third-party buyer. In addition, the market price may not necessarily reflect the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid with respect to the Trust Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase price paid by the Trust unitholder.

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, 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. 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.

Courts outside of Delaware may not recognize the limited liability of the Trust unitholders provided under Delaware law.

Under the Delaware Statutory Trust Act, Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of 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.

The operations of the Underlying Properties are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.

The oil and natural gas exploration and production operations on the Underlying Properties are subject to stringent and comprehensive federal, 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 numerous obligations that apply to the operations on the Underlying Properties, including the requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types, quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use; the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; and the imposition of substantial liabilities for pollution resulting from operations. For example, the EPA has published regulations that impose more stringent emissions control requirements for oil and gas development and production operations, which may require us, our operators, or third-party contractors to incur additional expenses to control air emissions from current operations and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other requirements. For example, in 2012 the EPA adopted federal New Source Performance Standards (“NSPS”) that require the reduction of volatile organic compound 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, and from pneumatic controllers and storage vessels. In June 2016, the EPA published a final rule adopting additional NSPS requirements for new, modified, or reconstructed oil and gas facilities that require control of the greenhouse gas methane from affected facilities, including requirements to find and repair fugitive leaks of methane emissions at well sites (“Methane Rule”). Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding that culminated in a 2019 rule proposal that would eliminate 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. The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations, which could reduce the profits available to the Trust and potentially impair the economic development of the Underlying Properties. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often times requiring difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas wastes, could impair the operators’ ability to produce oil and natural gas commercially from the Underlying Properties, which would reduce profits attributable to the Net Profits Interest.

There is inherent risk of incurring significant environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability for the removal or remediation of previously released materials or property contamination regardless of whether such operators were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. In addition, the risk of accidental spills or releases could expose the operators of the Underlying Properties to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and results of operations and could reduce the amount of cash available for distribution to Trust unitholders. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the Underlying Properties to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results of operations, competitive position or financial condition.

The Trust will indirectly bear 80% of all costs and expenses paid by the Sponsor, including those related to environmental compliance and liabilities associated with the Underlying Properties, including costs and liabilities resulting from conditions that existed prior to the Sponsor’s acquisition of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition, as a result of the increased cost of compliance, the operators of the Underlying Properties may decide to discontinue drilling.

Neither the Sponsor nor the Trust is generally entitled to, nor required to provide, indemnity to third party operators with respect to pollution liability and associated environmental remediation costs. However, the Sponsor may be required to provide, and may be entitled to, indemnity from third party operators with respect to such liabilities and costs in the event of the other party’s gross negligence or misconduct. In addition, the Sponsor has agreed to assume certain environmental liabilities of prior owners of the Underlying Properties in connection with the purchase thereof.

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 Sponsor 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 believes its general liability and excess liability insurance policies would 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 will be adequate to cover claims that may arise or that the Sponsor will 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 operations on the Underlying Properties are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available for distribution to Trust unitholders.

The production and development operations on the Underlying Properties are subject to complex and stringent laws and regulations. To conduct their operations in compliance with these laws and regulations, the operators of the Underlying Properties must obtain and maintain numerous permits, drilling bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting. The operators of the Underlying Properties may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations, and the Trust will bear an 80% share of these costs. In addition, the operators’ costs of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become applicable to their operations. Such costs could have a material adverse effect on the operators’ business, financial condition and results of operations and reduce the amount of cash received by the Trust in respect of the Net Profits Interest. The operators of the Underlying Properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets. To the extent the operators of the Underlying Properties are shippers on interstate pipelines, they must comply with the tariffs of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne in part by the Trust.

Laws and regulations governing exploration and production may also affect production levels. The operators of the Underlying Properties are required to comply with federal and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on the part of the operators and third party downstream natural gas transporters. These and other laws and regulations can limit the amount of oil and natural gas the operators can produce from their wells, limit the number of wells they can drill, or limit the locations at which they can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.

New laws or regulations, or changes to existing laws or regulations, may unfavorably impact the operators of the Underlying Properties and result in increased operating costs or have a material adverse effect on their financial condition and results of operations and reduce the amount of cash received by the Trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and hedging activities. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce the operators’ liquidity, delay the operators’ operations or otherwise alter the way the operators conduct their business, any of which could have a material adverse effect on the Trust and the amount of cash available for distribution to Trust unitholders.

Climate change laws and regulations restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause them to incur significant costs in preparing for or responding to those effects.

The oil and gas industry is a direct source of certain greenhouse gas (“GHG”) emissions, namely carbon dioxide and methane, and future restrictions on such emissions could impact future operations on the Underlying Properties. In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such gases are contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the federal Clean Air Act. The EPA has adopted rules that regulate emissions of GHGs from certain large stationary sources under the Prevention of Significant Deterioration (“PSD”) and Title V operating permit reviews for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology” standards that typically are established by the states.

In June 2014, the U.S. Supreme Court held that GHG alone cannot trigger an obligation to obtain an air permit. However, the Supreme Court upheld EPA’s authority to regulate GHG emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional criteria pollutant emissions must include a limit for GHG in their permit. These EPA rules could affect the operations on the Underlying Properties or the ability of the operators of the Underlying Properties to obtain air permits for new or modified facilities.

In June 2016, the EPA published the Methane Rule. Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding that that culminated in a 2019 rule proposal that would eliminate 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. The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations.

In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands that are substantially similar to the EPA’s Methane Rule. However, on December 8, 2017, the BLM published a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 2019, including those requirements relating to venting, flaring and leakage from oil and gas production activities. Further, in September 2018, the BLM published a final rule to revise or rescind certain provisions of the 2016 rule. While the future implementation of the EPA and BLM rules aimed at controlling GHG emissions from oil and natural gas sources remains uncertain, future federal GHG regulations for the oil and gas industry remain a possibility given the long-term trend towards increasing regulation, and the Underlying Properties may be subject to these requirements or become subject to them in the future.

In addition, from time to time the U.S. Congress has from considered legislation to reduce emissions of GHGs, and many states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap-and-trade programs work by requiring either major sources of emissions or major producers of fuels to acquire and surrender emission allowances, with the number of allowances available for purchase reduced each year until the overall GHG emission reduction goal is achieved. These reductions would be expected to cause the cost of allowances to escalate significantly over time. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from the equipment or operations of the operators of the Underlying Properties could require the operators to incur costs to monitor and report on GHG emissions or reduce emissions of GHGs associated with their operations. Such requirements could also adversely affect demand for the oil and natural gas produced, all of which could reduce profits attributable to the Net Profits Interest and, as a result, the Trust’s cash available for distribution.

Because regulation of GHG emissions is relatively new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG initiatives will impact the operators of the Underlying Properties and the Trust.

Finally, some scientists have concluded that increasing concentrations of greenhouse gases 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 effects were to occur, they could have an adverse effect on the operators’ assets and operations and, consequently, may reduce profits attributable to the Net Profits Interest and, as a result, the Trust’s cash available for distribution.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays as well as adversely affect the services of the operators of the Underlying Properties.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic fracturing. 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 2012 the EPA adopted federal NSPS that require the reduction of volatile organic compound 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, and from pneumatic controllers and storage vessels. In June 2016, the EPA published the Methane Rule. Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding that culminated in a 2019 rule proposal that would eliminate 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. The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations, which could reduce the profits available to the Trust and potentially impair the economic development of the Underlying Properties.

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 and also 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 might be considered or implemented in the jurisdictions in which the Underlying Properties are located.

If new laws or regulations that significantly restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in Texas, Louisiana or New Mexico, such legal requirements could make it more difficult or costly for the Sponsor or the third party operators to perform hydraulic fracturing activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic fracturing could reduce the amount of oil and natural gas that the operators are ultimately able to produce in commercially paying quantities from the Underlying Properties, and could increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require air emissions, water usage and chemical additives disclosures.

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 will be 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. 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 the bankruptcy of an 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 of time. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to Trust unitholders.

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, to the extent that were not the case, or to the extent 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.

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 distributions 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, 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.

Cyber-attacks or other failures in telecommunications or information technology systems could result in information theft, data corruption and significant disruption of the Sponsor’s business operations.

In recent years, the Sponsor has increasingly relied on information technology (“IT”) systems and networks in connection with its business activities, including certain of its exploration, development and production activities. the Sponsor relies on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication. These threats pose a risk to the security of the Sponsor’s systems and networks, the confidentiality, availability and integrity of its data and the physical security of its employees and assets. Any cyber-attack could have a material adverse effect on the Sponsor’s reputation, competitive position, business, financial condition and results of operations, and could have a material adverse effect on the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as significant additional expense to the Sponsor to implement further data protection measures.

In addition to the risks presented to the Sponsor’s systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack of this nature would be outside the Sponsor’s ability to control, but could have a material adverse effect on the Sponsor’s business, financial condition and results of operations, and could have a material adverse effect on the Trust.

Cyber-attacks or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption of the Trustee’s operations.

The Trustee depends heavily upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally from within the respective companies.

If a cyber-attack were to occur, it could potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust, which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

TAX RISKS RELATED TO THE TRUST UNITS

The Trust has not requested a ruling from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that the Trust is not a “grantor trust” for U.S. federal income tax purposes, the Trust could be subject to more complex and costly tax reporting requirements that could reduce the amount of cash available for distribution to Trust unitholders.

If the Trust were not treated as a grantor trust for U.S. federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.

If the Trust were treated for U.S. federal income tax purposes as a partnership, it likely would be subject to new audit procedures that for taxable years beginning after December 31, 2017, alter the procedures for auditing large partnerships and also alter the procedures for assessing and collecting income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an entity level tax on the Trust, and unitholders may have to bear the expense of the adjustment even if they were not Trust unitholders during the audited taxable year.

Neither the Sponsor nor the Trustee has requested a ruling from the IRS regarding the tax status of the Trust, and neither the Sponsor nor the Trust can provide any assurance that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.

Trust unitholders should be aware of the possible state tax implications of owning Trust Units.

Unitholders are required to pay taxes on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.

Trust unitholders are treated as if they own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as if no Trust were in existence. Because the Trust generates taxable income that could be different in amount than the cash the Trust distributes, unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s taxable income even if they receive no cash distributions from the Trust. A unitholder may not receive cash distributions from the Trust equal to such unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability that results from that income.

A portion of any tax gain on the disposition of the Trust Units could be taxed as ordinary income.

If a unitholder sells Trust Units, he or she will recognize a gain or loss equal to the difference between the amount realized and his or her tax basis in those Trust Units. A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion recapture.

The Trust allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Trust Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.

The Trust generally allocates its items of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Trust Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. It is possible that the IRS could disagree with this allocation method and could 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 Trust unitholders affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.

Trust unitholders should consult their tax advisors as to the specific tax consequences of the ownership and disposition of the of the Trust Units, including the applicability and effect of U.S. federal, state, local, and foreign income and other tax laws in light of their particular circumstances.

None.

Description of the Underlying Properties

The Underlying Properties consist of producing and non-producing interests in oil and natural gas units, wells and lands in Texas, Louisiana and New Mexico. The Underlying Properties include a portion of the assets in east Texas and north Louisiana acquired by Enduro from Denbury Resources Inc. in December 2010, and all of the assets in the Permian Basin of New Mexico and west Texas acquired by Enduro from Samson Investment Company and ConocoPhillips Company in January 2011 and February 2011, respectively. In August 2018, the Sponsor purchased the Underlying Properties from Enduro and assumed all of Enduro’s obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were parties. The Underlying Properties are divided into two geographic regions: the Permian Basin region and East Texas/North Louisiana region.

As of December 31, 2019, the Underlying Properties had proved reserves of 16.9 MMBoe with 80% and 91% of the volumes and PV-10 value, respectively, attributable to proved developed reserves. Substantially all of the 16.9 MMBoe of proved reserves, based on PV-10 value, were operated by third-party operators.

The Sponsor’s interests in the Underlying Properties require the Sponsor to bear its proportionate share of the costs of development and operation of such properties. As of December 31, 2019, the Sponsor held average working interests of approximately 25% and 18% and average net revenue interests of approximately 21% and 13% in the Underlying Properties located in the Permian Basin and East Texas/North Louisiana regions, respectively. The Underlying Properties are also burdened by non-cost bearing interests owned by third parties consisting primarily of overriding royalty and royalty interests.

Reserves

Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”), independent petroleum and geological engineers, estimated crude oil (including natural gas liquids) and natural gas proved reserves of the Underlying Properties’ full economic life and for the Trust life as of December 31, 2019. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary significantly from the original estimates. In addition, the reserves and net revenues attributable to the Net Profits Interest include only 80% of the reserves attributable to the Underlying Properties that are expected to be produced within the term of the Net Profits Interest.

The independent petroleum engineer’s report as to the proved oil and natural gas reserves as of December 31, 2019 was prepared by Cawley Gillespie. Cawley Gillespie, whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties and the Net Profits Interest attributable to the Trust is W. Todd Brooker. Mr. Brooker has been a petroleum consultant for Cawley Gillespie since 1992 and is currently the Senior Vice President. He is a registered professional engineer in the State of Texas (license no. 83462) and a graduate of the University of Texas with a Bachelor of Science in Petroleum Engineering.

Information concerning changes in net proved reserves attributable to the Trust, and the calculation of the standardized measure of the related discounted future net revenues is contained in the notes to the financial statements of the Trust included in this Form 10-K. The Sponsor has not filed reserve estimates covering the Underlying Properties with any other federal authority or agency.

The following table summarizes the estimated proved reserve quantities and PV-10 attributable to the Trust and Underlying Properties as of December 31, 2019 and 2018:

Reserve quantities and revenues for the Net Profits Interest were estimated from projections of reserves and revenues attributable to the Underlying Properties. Since the Trust has a defined Net Profits Interest, the Trust does not own a specific percentage of the oil and natural gas reserve quantities. Accordingly, reserves allocated to the Trust pertaining to its 80% Net Profits Interest in the Underlying Properties have effectively been reduced to reflect recovery of the Trust’s 80% portion of applicable production and development costs. Because Trust reserve quantities are determined using an allocation formula, any changes in actual or assumed prices or costs will result in revisions to the estimated reserve quantities allocated to the Net Profits Interest.

Estimates of proved reserves were prepared in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements. Prices used in estimating reserves were as follows: 

Changes in Proved Undeveloped Reserves

During the year ended December 31, 2019, proved undeveloped reserves of the Underlying Properties increased 119 MMBoe due to modest reserve estimate increases for the booked, non-operated Wolfcamp shale wells in the Permian Basin of west Texas and the Haynesville shale of Louisiana. Compared to the year ended December 31, 2018, the same amount of proved undeveloped gross wells were recognized in the reserves of the Underlying Properties when compared to the year ended December 31, 2019. The revision increases by Cawley Gillespie are a result of the inclusion of more recent production history of the ongoing development activity for the Underlying Properties. The following is a summary of the changes in quantities of proved undeveloped reserves for the Underlying Properties during the year ended December 31, 2019:

Producing Acreage and Well Counts

For the following data, “gross” refers to the total number of wells or acres in the Underlying Properties and “net” refers to gross wells or acres multiplied by the percentage working interest owned by the Sponsor and in turn attributable to the Underlying Properties. All of the acreage comprising the Underlying Properties is held by production. Although many wells produce both oil and natural gas, a well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.

The Underlying Properties are interests in properties located in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region. The following is a summary of the approximate acreage of the Underlying Properties at December 31, 2019:

The following is a summary of the producing wells on the Underlying Properties as of December 31, 2019:

The following is a summary of the number of development and exploratory wells drilled on the Underlying Properties located in the Permian Basin and East Texas/North Louisiana during the last three years:

Major Producing Areas

Substantially all of the Underlying Properties are located in mature oil fields that are characterized by long production histories. Based on the reserve reports, approximately 63% of the future production from the Underlying Properties is expected to be oil and approximately 37% is expected to be natural gas.

Permian Basin Region

The Permian Basin is one of the largest and most prolific oil and natural gas producing basins in the United States. The Underlying Properties in the Permian Basin contain 123,367 gross (36,580 net) acres in Texas and New Mexico.

The largest fields in the Underlying Properties are located primarily in the Permian Basin (measured by Boe reserves at December 31, 2019). Each of the following fields individually account for more than 15 percent of the Underlying Properties reserves as of December 31, 2019:

The following table shows the average sales price and lease operating expenses for any field that individually accounted for more than 15 percent of the Underlying Properties’ reserves as of the end of the respective period. The figures presented for the largest fields in the Permian Basin of west Texas and New Mexico below relate to the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2019, 2018 and 2017.

East Texas/North Louisiana Region

The Underlying Properties contain interests in 12,629 gross (4,899 net) acres in the East Texas/North Louisiana region across three fields: the Elm Grove field, operated primarily by Aethon Energy Operating, LLC and BHP Billiton Ltd.; the Kingston field, operated by EXCO Resources and Indigo Resources, LLC; and the Stockman field, operated by COERT. Substantially all proved reserves attributable to the Underlying Properties in the East Texas/North Louisiana region are located in the Haynesville, Cotton Valley, and Hosston reservoirs of the Elm Grove and Kingston fields. Proved reserves attributable to the Underlying Properties in the Elm Grove and Kingston fields were 1.0 MMBoe and 0.1 MMBoe, respectively, as of December 31, 2019.

Production and Reserves

The following table shows the net production, average sales price, average lease operating expense, and proved reserves as of year-end for the Underlying Properties located in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region, which relates to the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2019, 2018, and 2017.

Abandonment and Sale of Underlying Properties

Each of the operators of the Underlying Properties or any transferee has the right to abandon its interest in any well or property if it reasonably believes a well or property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the portion of the Net Profits Interest relating to the abandoned property will be extinguished.

The Sponsor generally may sell all or a portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent of the Trust unitholders. 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. 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 less than or equal to 0.25% 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 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 the Trust receiving an amount equal to the fair value to the Trust of such Net Profits Interest. In January 2019, the Sponsor sold two producing wells and associated acreage of the Underlying Properties under this provision for a sale price of approximately $62,000, and the Trustee released such properties from the Net Profits Interest.

Title to Properties

The properties comprising the Underlying Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens and obligations affect the Sponsor’s rights to production or the value of production from the Underlying Properties, they have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves attributable to the Underlying Properties.

The Sponsor’s interests in the oil and natural gas properties comprising the Underlying Properties are typically subject to one or more of the following:

The Sponsor has informed the Trustee that the Sponsor believes the burdens and obligations affecting the properties comprising the Underlying Properties are conventional in the industry for similar properties. The Sponsor has also informed the Trustee that the Sponsor believes the existing burdens and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially adversely affect the Net Profits Interest or its value.

To give third parties notice of the Net Profits Interest, Enduro recorded the Conveyance in Texas, Louisiana and New Mexico in the real property records in each Texas, Louisiana or New Mexico county in which the Underlying Properties are located, or in such other public records of those states as required under applicable law to place third parties on notice of the Conveyance.

In a bankruptcy of the Sponsor, to the extent 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. See “Risk Factors—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” in Item 1A of this Form10-K.

The Sponsor believes that its title to the Underlying Properties and the Trust’s title to the Net Profits Interest are each good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from the use or value of such Underlying Properties or Net Profits Interest. Under the terms of the Conveyance creating the Net Profits Interest, the Sponsor has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens and obligations described in this section. Please see “Risk Factors—The Trust Units may lose value as a result of title deficiencies with respect to the Underlying Properties” in Item 1A of this Form 10-K.

Currently, there are not any legal proceedings pending to which the Trust is a party or of which any of its property is the subject. The foregoing does not address any legal proceedings to which the Sponsor or any of the third-party operators may be a party or subject or that may otherwise relate to or affect any of the Underlying Properties or the operations of any of the operators of the Underlying Properties.

Not applicable.

PART II

The Trust Units trade on the New York Stock Exchange under the symbol “PVL.” At December 31, 2019, there were 33,000,000 Trust Units outstanding. On March 9, 2020, there were four unitholders of record. This number does not include owners for whom Trust Units may be held in “street” name.

Distributions

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 incurred expenses 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 tenth business day after the record date (or the next succeeding business day). For further information on distributions to unitholders, see Note 7 of the Notes to Financial Statements in Item 8 of this Form 10-K.

Equity Compensation Plans

The Trust does not have any employees and does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

There were no equity securities sold by the Trust during the year ended December 31, 2019.

Purchases of Equity Securities

There were no purchases of Trust Units by the Trust or any affiliated purchaser during the fourth quarter of 2019.

As a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K, the Trust is not required to provide information required by this Item.

This discussion contains forward-looking statements. Please refer to “Forward-Looking Statements” for an explanation of these types of statements.

Overview

Permianville Royalty Trust, previously known as Enduro Royalty Trust, a statutory trust created in May 2011, completed its initial public offering in November 2011. The Trust’s only asset and source of income is the Net Profits Interest, which entitles the Trust to receive 80% of the net profits from oil and natural gas production from the Underlying Properties. The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. Additionally, third parties operate substantially all of the wells on the Underlying Properties and, therefore, the Sponsor is not in a position to control the timing of development efforts, associated costs, or the rate of production of the reserves.

The Trust is required to make monthly cash distributions of substantially all of its monthly cash receipts, after deducting the Trust’s administrative expenses, to holders of record (generally the last business day of each calendar month) on or before the tenth business day after the record date. The Net Profits Interest is entitled to a share of the profits from and after July 1, 2011 attributable to production occurring on or after June 1, 2011. The amount of Trust revenues and cash distributions to Trust unitholders depends on, among other things:

Generally, the Sponsor receives cash payment for oil production 30 to 60 days after it is produced and for natural gas production 60 to 90 days after it is produced.

2019 Recap and 2020 Outlook

The average NYMEX oil price and gas price received for the production months included in 2019 distributions decreased 8% and 9%, respectively, from the prior year as a result of the corresponding increase in the average NYMEX oil price and average NYMEX gas price for the relevant production months.

In 2019, the exploratory activity on the Underlying Properties included the successful drilling and completion of three gross wells in the Haynesville area of Louisiana and two gross wells in the Permian area.

Crude oil prices have declined sharply in the first quarter of 2020 in response to the economic effects of the coronavirus pandemic and the recent announcement of planned production increases by Saudi Arabia. Such factors, if they persist for the near term or longer, could adversely affect the operators of the Underlying Properties, production from the Underlying Properties and/or distributions to Trust unitholders.

The operators of the Underlying Properties continue to evaluate planned capital expenditures during 2020, but based on currently available information, the Sponsor anticipates 2020 capital expenditures to range from $4 million to $6 million  attributable to the properties in which the Trust owns a net profits interest, or $3 million to $5 million net to the Trust’s 80% net profits interest.

Results of Operations

The following table displays oil and natural gas sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for the distributions paid during the years ended December 31, 2019, 2018, and 2017.

Computation of Income from Net Profits Interest Received by the Trust

In connection with the closing of the initial public offering in November 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 newly issued Trust Units. The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale and production of oil and natural gas attributable to the Underlying Properties that are produced during the term of the Conveyance, which commenced on July 1, 2011. The Trust’s Income from Net Profits Interest consists of monthly net profits attributable to the Income from Net Profits Interest. Net profits income for the years ended December 31, 2019, 2018, and 2017 was determined as shown in the following table:

In 2017, there were two months in which direct operating and development expenses exceeded revenues, thereby causing net profits on the Underlying Properties to be negative. As a result, there were no distributions to Trust unitholders in November or December 2017 and the aggregate shortfall in net profits of $526,709 was carried forward to be deducted from future net profits generated by the Underlying Properties in 2018. As the net profits for these two months in 2017 was negative and there was no distribution paid to unitholders, revenues and the associated direct operating and development expenses are excluded from the calculation of distributable income detailed in the table above for the year ended December 31, 2017 as well as the related sales volumes detailed below.

In January 2018, net profits from the Underlying Properties were positive, and the aggregate shortfall in net profits of $526,709 from November and December 2017 was deducted from such net profits when calculating distributions paid in January 2018. Since the 2017 shortfall in net profits was recovered in 2018 and included in 2018 distributions paid to unitholders, revenues and the associated direct operating and development expenses for November and December 2017 are included in the calculation of distributable income detailed in the table above for the year ended December 31, 2018 as well as the related sales volumes detailed below.

The following table displays oil and natural gas sales volumes and average prices from the Underlying Properties, representing the amounts included in the net profits calculation for distributions paid during the years ended December 31, 2019, 2018, and 2017:

Years Ended December 31, 2019 and 2018

Net profits attributable to the Underlying Properties for the year ended December 31, 2019 are calculated from the following:

Net profits attributable to the Underlying Properties for the year ended December 31, 2019 were $12.1 million compared to $19.1 million for the year ended December 31, 2018. As a result of direct operating expenses and development expenses exceeding oil and natural gas sales for the last two months of 2017, the Trust did not pay a distribution to unitholders for the last two months of 2017. Under the modified cash basis of accounting, as there was no distribution in November and December 2017, the oil and natural gas sales, direct operating expenses and development expenses for such periods are not included in the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2017 but are included in the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2018. Therefore, several variances between years are due to the inclusion of twelve months of results in the year ended December 31, 2019 compared to fourteen months in the year ended December 31, 2018. The $7.0 million decrease in net profits attributable to the Underlying Properties from 2018 to 2019 was primarily due to the following items:

In 2017, pursuant to an agreement between Enduro and the Trust, Enduro withheld $0.8 million (the “Holdback Amount”) from the net proceeds allocable to the Trust from the sale by Enduro of certain properties in the Permian Basin. This amount was intended to cover possible indemnification obligations arising within 25 months of the of the closing of the sale, or by the end of October 2019 (the “Indemnification Period”). In connection with the Sale Transaction, Enduro released the Holdback Amount to the Trustee on September 4, 2018. The Trustee retained the Holdback Amount for the remainder of the Indemnification Period and released the Holdback Amount totaling $0.8 million, including interest, as part of the Trust distribution to unitholders paid in October 2019.

The Trust withheld $0.8 million and paid $0.9 million for general and administrative expenses during the year ended December 31, 2019. Expenses paid during the period primarily consisted of fees for the preparation of 2018 tax information for unitholders, preparation of the Trust’s 2018 reserve report and Annual Report on Form 10-K, 2018 and 2019 financial statement audit fees, preparation of the Trust’s 2019 monthly press releases and Quarterly Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees. For the year ended December 31, 2018, the Trust withheld $0.5 million and paid $1.1 million for general and administrative expenses.

Years Ended December 31, 2018 and 2017

Net profits attributable to the Underlying Properties for the year ended December 31, 2018 are calculated from the following:

Net profits attributable to the Underlying Properties for the year ended December 31, 2018 were $19.1 million compared to $9.4 million for the year ended December 31, 2017. As a result of direct operating expenses and development expenses exceeding oil and natural gas sales for the last two months of 2017, the Trust did not pay a distribution to unitholders for the last two months of 2017. Under the modified cash basis of accounting, as there was no distribution in November and December 2017, the oil and natural gas sales, direct operating expenses and development expenses for such periods are not included in the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2017 but are included in the table above or this analysis of net profits attributable to the Underlying Properties for the year ended December 31, 2018. Therefore, several variances between years are due to the inclusion of fourteen months of results in the year ended December 31, 2018 compared to ten months in the year ended December 31, 2017. The $9.6 million increase in net profits attributable to the Underlying Properties from 2017 to 2018 was primarily due to the following items:

In September 2017, Enduro completed the sale of certain properties in the Permian Basin and, in connection with the sale, the Trust released its 80% Net Profits Interest in the properties in exchange for 80% of the net proceeds of the sales. The net proceeds of the sales were paid to Trust unitholders in a special distribution in October 2017. During the first quarter of 2018, $35,283 in general and administrative expenses incurred and paid by Enduro that were not initially charged to the Trust as part of the special distribution were deducted in calculating the net profits attributable to the Underlying Properties. Further, during the second quarter of 2018, $52,960 was deducted from the net profits attributable to the Underlying Properties due to the inclusion in prior period distribution calculations of certain expenses and revenues that related to properties sold as part of these divestitures. This resulted in total adjustments to the net profits attributable to the Underlying Properties for 2018 of $88,243.

The Trust withheld $0.5 million and paid $1.1 million for general and administrative expenses during the year ended December 31, 2018. Expenses paid during the period primarily consisted of fees for the preparation of 2017 tax information for unitholders, preparation of the Trust’s 2017 reserve report and Annual Report on Form 10-K, 2017 and 2018 financial statement audit fees, preparation of the Trust’s 2018 monthly press releases and Quarterly Reports on Form 10-Q, Trustee fees, and New York Stock Exchange listing fees. For the year ended December 31, 2017, the Trust withheld $0.9 million and paid $0.7 million for general and administrative expenses.

Liquidity and Capital Resources

The Trust’s principal sources of liquidity are cash flow generated from the Net Profits Interest and borrowing capacity under the letter of credit described below. Other than Trust administrative expenses, including any reserves established by the Trustee for future liabilities, the Trust’s only use of cash is for distributions to 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) in any given month, over the Trust’s expenses paid for that month. Available funds are reduced by any cash the Trustee determines to hold as a reserve against future expenses.

The Trustee may create a cash reserve to pay for future liabilities of the Trust. If the Trustee determines that the cash on hand and the cash to be received are, or will be, insufficient to cover the Trust’s liabilities, the Trustee may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust that exceed cash held by the Trust. The Trustee may authorize the Trust to borrow from any person, including the Trustee or the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee or any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were to be loaned by the entity serving as Trustee or Delaware Trustee or an affiliate thereof, would be similar to the terms which such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship. In addition, the Sponsor has provided the Trust with a $1.2 million letter of credit to be used by the Trust if its cash on hand (including available cash reserves) is insufficient to pay ordinary course administrative expenses. Further, if the Trust requires more than the $1.2 million under the letter of credit to pay administrative expenses, the Sponsor has agreed to loan funds to the Trust necessary to pay such expenses. Any loan made by the Sponsor to the Trust would be evidenced by a written promissory note, be on an unsecured basis, and have terms that are no less favorable to the Sponsor than those that would be obtained in an arm’s length transaction between the Sponsor and an unaffiliated third party. If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust unitholders until such amounts borrowed or drawn are repaid. Except for the foregoing, the Trust has no source of liquidity or capital resources. The Trustee has no current plans to authorize the Trust to borrow money other than Sponsor advances to pay the Trust’s monthly operating expenses. At December 31, 2019 and 2018, the Trust held cash reserves of $90,665 and $827,169, respectively, for future Trust expenses. Since its formation, the Trust has not borrowed any funds other than Sponsor advances to pay the Trust’s monthly operating expenses and no amounts have been drawn on the letter of credit.

From time to time, if the Trust’s cash on hand (including available cash reserves, if any) is not sufficient to pay the Trust’s ordinary course administrative expenses that are due prior to the monthly payment to the Trust of proceeds from the Net Profits Interest, COERT may advance funds to the Trust to pay such expenses. Such advances are recorded as a liability on the Statements of Assets, Liabilities and Trust Corpus until repaid. As of December 31, 2019 and 2018, Advances to the Trust were $34,818 and $0, respectively.

In February 2016, Enduro established a $750,000 reserve from that month’s net profits interest calculation for approved 2016 development expenses. The Trust, in its discretion, also withheld $250,000 for anticipated future liabilities of the Trust. In March 2016, Enduro withheld an additional $100,000 to increase the previously established reserve for approved development expenses, a total reserve of $850,000. As a result of lower than anticipated expenditures during the year, over the course of the remaining 2016 distributions Enduro released $750,000 of the established reserve, thereby increasing the net profits attributable to the Trust. In the distribution paid in January 2017, Enduro released the final $100,000 reserve. COERT currently does not maintain any reserve for development expenses.

Cash held by the Trustee as a reserve against future liabilities or for distribution at the next distribution date may be held in a noninterest-bearing account or may be invested in:

Neither Enduro nor the Sponsor has entered into any hedge contracts relating to oil and natural gas volumes produced from the Underlying Properties, attributable to the Net Profits Interest for the years ended December 31, 2019, 2018 or 2017, and the terms of the Conveyance prohibit COERT from entering into new hedging arrangements burdening the Trust.

The Trust pays the Trustee an administrative fee of $200,000 per year. The Trust pays the Delaware Trustee an annual fee of $2,000. The Trust also incurs, either directly or as a reimbursement to the Trustee, legal, accounting, tax and engineering fees, printing costs and other expenses that are deducted by the Trust before distributions are made to Trust unitholders. The Trust also is responsible for paying other expenses incurred as a result of being a publicly traded entity, including costs associated with annual and quarterly reports to Trust unitholders, tax return and Form 1099 preparation and distribution, NYSE listing fees, independent auditor fees and registrar and transfer agent fees.

The Trust does not have any transactions, arrangements or other relationships with unconsolidated entities or persons that could materially affect the Trust’s liquidity or the availability of capital resources.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Contractual Obligations

As of December 31, 2019, the Trust had no obligations or commitments to make future contractual payments other than the administrative fee payable to the Trustee and the Delaware Trustee. See “Certain Relationships and Related Transactions, and Director Independence—Trustee Administrative Fee” in Item 13 of this Form 10-K.

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

Critical Accounting Policies and Estimates

The Trust uses the modified cash basis of accounting to report Trust receipts of income from the Net Profits Interest and payments of expenses incurred. 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 plus any payments made or net payments received in connection with the settlement of certain hedge contracts, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust pursuant to terms of the conveyance creating the Net Profits Interest.

Under the terms of the Conveyance, the monthly Net Profits Interest calculation includes oil and natural gas revenues received. Monthly operating expenses and capital expenditures represent incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.

The financial statements of the Trust are prepared on the following basis:

(a) Income from Net Profits Interest is recorded when distributions are received by the Trust;

(b) Distributions to Trust unitholders are recorded when paid by the Trust;

(c) Trust general and administrative expenses (which includes the Trustee’s fees as well as accounting, engineering, legal, and other professional fees) are recorded when paid;

(d) Cash reserves for Trust expenses may be established by the Trustee for certain future expenditures that would not be recorded as contingent liabilities under accounting principles generally accepted in the United States of America (“GAAP”);

(e) Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis and is charged directly to the Trust corpus. Such amortization does not affect cash earnings of the Trust; and

(f) The Net Profits Interest in oil and natural gas properties is periodically assessed whenever events or circumstances indicate that the aggregate value may have been impaired below its total capitalized cost based on the Underlying Properties. If an impairment loss is indicated by the carrying amount of the assets exceeding the sum of the undiscounted expected future net cash flows of the Net Profits Interest, then an impairment loss is recognized for the amount by which the carrying amount of the asset exceeds its estimated fair value determined using discounted cash flows.

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; general and administrative expenses are recorded when paid instead of when incurred; and amortization of the net profits interest calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.

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 preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Oil and Natural Gas Reserves. The proved oil and natural gas reserves for the Underlying Properties are estimated by independent petroleum engineers. Reserve engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices, may justify revision of such estimates. Because proved reserves are required to be estimated using prices at the date of the evaluation, estimated reserve quantities can be significantly impacted by changes in product prices. Accordingly, oil and natural gas quantities ultimately recovered and the timing of production may be substantially different from original estimates.

The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and natural gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month benchmark price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and natural gas reserves. Changes in any of these assumptions, including consideration of other factors, could have a significant impact on the standardized measure. The standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Net Profits Interest. The Trust calculates amortization of the Net Profits Interest in oil and natural gas properties on a unit-of-production basis based on the Underlying Properties’ production and reserves. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is recorded on sales volumes paid by the Trust during the relevant period and is charged directly to the Trust corpus balance. As a result, amortization does not affect the cash earnings of the Trust.

Impairment of Net Profits Interest. The Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. The Trust did not realize any impairment during the years ended December 31, 2019, 2018 or 2017. Future downward revisions in actual production volumes relative to current forecasts, higher than expected operating costs, or lower than anticipated market pricing could result in recognition of impairment in future periods. Any impairment of the Net Profits Interest will result in a non-cash charge to Trust corpus and will not affect distributable income. For further information, see “Note 5. Fair Value Measurements” of the Notes to Financial Statements in Item 8 of this Form 10-K.

As a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K, the Trust is not required to provide information required by this Item.

Report of Independent Registered Public Accounting Firm

To the Trustee and Unitholders of Permianville Royalty Trust:

Opinion on the Financial Statements

We have audited the accompanying statements of assets, liabilities, and trust corpus of Permianville Royalty Trust (the Trust) as of December 31, 2019 and 2018, the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Trust at December 31, 2019 and 2018, and its distributable income for each of the three years in the period ended December 31, 2019, in conformity with the modified cash basis of accounting, as described in Note 2, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Trust's internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 16, 2020 expressed an unqualified opinion thereon.

Basis of Accounting

As described in Note 2 to the financial statements, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

Basis for Opinion

These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Trust’s auditor since 2011.

Houston, Texas

   March 16, 2020

PERMIANVILLE ROYALTY TRUST

Statements of Assets, Liabilities and Trust Corpus

The accompanying notes to financial statements are an integral part of these statements.

PERMIANVILLE ROYALTY TRUST

Statements of Distributable Income

The accompanying notes to financial statements are an integral part of these statements.

PERMIANVILLE ROYALTY TRUST

Statements of Changes in Trust Corpus

The accompanying notes to financial statements are an integral part of these statements.

PERMIANVILLE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS

1.       TRUST ORGANIZATION AND PROVISIONS

Permianville Royalty Trust (the “Trust”), previously known as Enduro Royalty Trust, is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying Properties.”

In connection with the closing of the initial public offering in November 2011, Enduro contributed the Net Profits Interest to the Trust in exchange for 33,000,000 units of beneficial interest in the Trust (the “Trust Units”). Through the initial public offering in 2011 and a secondary offering in 2013, Enduro sold a total of 24,400,000 Trust Units. As of December 31, 2017, Enduro owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.

At a special meeting of Trust unitholders held on August 30, 2017, unitholders approved several proposals, including amendments to the Trust Agreement. In September 2017, 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 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 75% to 50% of the outstanding units of the Trust.

In July 2018 Enduro entered into a purchase and sale agreement with COERT Holdings 1 LLC (“COERT” or the “Sponsor”) for the Underlying Properties and all of the outstanding Trust Units owned by Enduro (the “Sale Transaction”), and on August 31, 2018, the parties closed the Sale Transaction. In connection with the Sale Transaction, COERT assumed all of Enduro’s obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were parties. As of December 31, 2019, the Sponsor owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.

The Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying Properties. The Trust Agreement provides, among other provisions, that:

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NOTES TO FINANCIAL STATEMENTS—Continued

2.       SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Accounting

The Trust uses the modified cash basis of accounting to report Trust receipts of income from the Net Profits Interest and payments of expenses incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating expenses (including lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied by 80%. Cash distributions of the Trust are made based on the amount of cash received by the Trust from the Sponsor pursuant to terms of the Conveyance creating the Net Profits Interest.

Under the terms of the Conveyance, the monthly Net Profits Interest calculation includes oil and natural gas revenues received by the Sponsor during the relevant month. Monthly operating expenses and capital expenditures represent estimated incurred expenses, and as a result, represent accrued expenses as well as expenses paid during the period.

The financial statements of the Trust are prepared on the following basis:

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NOTES TO FINANCIAL STATEMENTS—Continued

The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; general and administrative expenses are recorded when paid instead of when incurred; and amortization of the net profits interest calculated on a unit-of-production basis is charged directly to trust corpus instead of as an expense. While these statements differ from financial statements prepared in accordance with GAAP, the modified cash basis of reporting revenues, expenses, and distributions is considered to be the most meaningful because monthly distributions to the Trust unitholders are based on net cash receipts.

This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission (“SEC”) as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts.

Use of Estimates

The preparation of financial statements in conformity with the basis of accounting described above requires the Trust to make estimates and assumptions that affect reported amounts of assets and liabilities and the reported amounts of revenues and expenses during the reporting period. Significant estimates affecting these financial statements include estimates of proved oil and natural gas reserves, which are used to compute the Trust’s amortization of net profits interest and its impairment assessments. Although the Trustee believes that these estimates are reasonable, actual results could differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks, money market accounts, and all highly liquid investments with an original maturity of three months or less.

Impairment

The Net Profits Interest in oil and natural gas properties is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. While the Trust did not record an impairment during the years ended December 31, 2019, 2018 or 2017, 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.

New Accounting Pronouncements

As the Trust’s financial statements are prepared on the modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements. No new accounting pronouncements have been adopted or issued that would impact the financial statements of the Trust.

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NOTES TO FINANCIAL STATEMENTS—Continued

3.       NET PROFITS INTEREST IN OIL AND NATURAL GAS PROPERTIES

The Net Profits Interest in oil and natural gas properties was recorded at its fair value on the date of conveyance. Amortization of the Net Profits Interest in oil and natural gas properties is calculated on a unit-of-production basis based on the Underlying Properties’ production and reserves. As the Trust uses the modified cash basis of accounting, amortization is recognized only in those months for which income from net profits interest exceeds capital expenditures. The reserves upon which the amortization rate is based are quantity estimates which are subject to numerous uncertainties inherent in the estimation of proved reserves. The volumes considered to be commercially recoverable fluctuate with changes in commodity prices and operating costs. These estimates are expected to change as additional information becomes available in the future. Downward revisions in proved reserves may result in an increased rate of amortization. Amortization is charged directly to the Trust corpus balance and does not affect the distributable income of the Trust. Accumulated amortization as of December 31, 2019 and 2018 was $279,925,202 and $273,834,138, respectively. 

The Net Profits Interest is periodically assessed for impairment whenever events or circumstances indicate that the current fair value based on expected future cash flows of the Underlying Properties may be less than the carrying value of the Net Profits Interest. While the Trust did not record an impairment during the years ended December 31, 2019, 2018 or 2017, 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. For further information, see “Note 5. Fair Value Measurements.”

As further discussed in “Note 4. Divestiture of Net Profits Interest in Certain Permian Basin Properties,” in September 2017, Enduro completed the sale of certain properties in the Permian Basin and, in connection with the sale, the Trust released its 80% Net Profits Interest in the properties in exchange for 80% of the net proceeds of the sales. As a result of the divestiture, and concurrent with the distribution of cash to the Trust that occurred in October 2017, the Trust reduced the carrying value of the Net Profits Interest reflected on the accompanying Statement of Assets, Liabilities and Trust Corpus by $1,650,000, which was the portion of the net sales proceeds allocated to producing properties. The remainder of the net sales proceeds, totaling $36,300,165, was attributed to the sale of the net profits interest on undeveloped acreage and not reflected in the carrying value of the Net Profits Interest. See “Note 5. Fair Value Measurements” for further discussion of the fair value of the divested properties, which was the basis for allocating net proceeds between producing properties and undeveloped acreage.

4.        DIVESTITURE OF NET PROFITS INTEREST IN CERTAIN PERMIAN BASIN PROPERTIES

In June 2017, Enduro notified the Trustee that Enduro had entered into eight separate purchase and sale agreements to divest certain acreage and associated production in the Permian Basin (the “Divestiture Properties”) that constituted part of the Underlying Properties and were therefore burdened by the Trust’s Net Profits Interest. On August 30, 2017, at a special meeting of Trust unitholders, the unitholders approved (i) the eight transactions pursuant to which Enduro would sell the Divestiture Properties, (ii) the release of the Trust’s 80% Net Profits Interest in the Divestiture Properties, and (iii) the related proposals to effect the sale transactions in exchange for the Trust receiving 80% of the net proceeds from the sale of the Divestiture Properties.

In September 2017, 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 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 75% to 50% of the outstanding units of the Trust. To effect the same changes as those included in the amended Trust Agreement, Enduro, the Trustee and the Delaware Trustee also entered into the First Amendment to Conveyance of Net Profits Interest. As a result of the Trust unitholders approving amendments to the Trust Agreement and Conveyance and the approval of the divestiture of the Divestiture Properties, Enduro and the Trustee entered into the Partial Release, Reconveyance and Termination Agreement (the “Partial Release”). Pursuant to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated and released to Enduro the Net Profits Interest with respect to the Divestiture Properties sold pursuant to eight letter agreements or purchase and sale agreements, as applicable, entered into between Enduro and eight separate counterparties.

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NOTES TO FINANCIAL STATEMENTS—Continued

In September 2017, Enduro completed the sale of the Divestiture Properties. The following table displays the aggregate net proceeds from the sale of the Divestiture Properties and the aggregate net proceeds allocable to Trust unitholders:

Total proceeds received by Enduro from the sale of the Divestiture Properties, after preliminary closing adjustments, were approximately $49.1 million. After deducting transaction expenses of $766,737, net proceeds to Enduro were $48.4 million, of which the proceeds allocable to the Trust were $38.7 million in accordance with its 80% Net Profits Interest. Pursuant to an agreement between Enduro and the Trust, Enduro withheld $750,000 (the “Holdback Amount”) of the net proceeds allocable to the Trust to cover possible indemnification obligations under the purchase and sale agreements within 25 months of the closing of the transactions, or by the end of October 2019 (the “Indemnification Period”). As a result of these transactions, a special distribution of $1.150005 per unit was paid on October 20, 2017 to Trust unitholders. In connection with the Sale Transaction, Enduro released the Holdback Amount to the Trustee on September 4, 2018. The Trustee retained the Holdback Amount for the remainder of the Indemnification Term and released the Holdback Amount, totaling approximately $752,000, including interest, as part of the Trust distribution to unitholders paid in October 2019.

As discussed in “Note 5. Fair Value Measurements,” the cash distributed to Trust unitholders as a result of the divestitures of the Net Profits Interest was allocated between producing properties and undeveloped acreage based on the fair value of the Divestiture Properties. The $1,650,000 allocated to producing properties reduced the carrying value of the “Net profits interest in oil and natural gas properties, net” line item on the Statement of Assets, Liabilities and Trust Corpus at December 31, 2017 and is shown as “Income from sale of net profits interest on producing properties” on the Statement of Distributable Income for the year ended December 31, 2017. The remaining amount totaling $36,300,165 was allocated to undeveloped acreage and is reflected in the Statement of Distributable Income as “Income from sale of net profits interest on undeveloped acreage.” As the proceeds received from the sale of the Divestiture Properties were primarily attributable to undeveloped acreage, the net profits generated from the Divestiture Properties have been insignificant to the Trust historically.

5.       FAIR VALUE MEASUREMENTS

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The three approaches for measuring the fair value of assets and liabilities are the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset, often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.

The fair value accounting standards do not prescribe which valuation technique should be used when measuring fair value and do not prioritize among the techniques. These standards establish a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy, while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

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NOTES TO FINANCIAL STATEMENTS—Continued

Valuation techniques that maximize the use of observable inputs are favored. Assets and liabilities are classified in their entirety based on the lowest priority level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Fair Values—Non-recurring

Divestiture of Net Profits Interest

In connection with the divestiture of the Net Profits Interest as discussed in Note 4, the fair value of the producing properties sold in relation to the fair value of the Underlying Properties was evaluated utilizing an undiscounted cash flow model as of the date of sale. This fair value measurement using an income approach was based upon internal estimates of future production levels, prices, drilling and operating costs and discount rates, which are Level 3 inputs. Internal price estimates were developed based on third-party longer-term commodity futures price outlooks. Based on this analysis, the expected future net cash flows of the producing properties sold discounted at an annual rate of 10 percent was approximately $2.2 million, representing approximately 1.7% of the total expected future net cash flows of the Underlying Properties discounted at an annual rate of 10 percent.

As the producing properties sold by Enduro represented 1.7% of the fair value of the Underlying Properties, the Trust reduced the carrying value of the Net Profits Interest reflected on its financial statements by 1.7%, or approximately $1.7 million, in October 2017.

Impairment of Net Profits Interest

Although the Trust did not record an impairment during the years ended December 31, 2019, 2018 or 2017, it is reasonably possible that the estimates of undiscounted future net cash flows attributable to the Underlying Properties may change in the future resulting in the need to further impair the carrying value of the Net Profits Interest. The primary factors that may affect estimates of future cash flows include: revisions, both positive and negative, to estimates of oil and natural gas reserves; changes in estimated average realized oil and natural gas prices; and results of future drilling activities.

6.       INCOME TAXES

Federal Income Taxes

For federal income tax purposes, the Trust is a grantor trust and therefore is not subject to tax at the trust level. Trust unitholders are treated as owning a direct interest in the assets of the Trust, and each Trust unitholder is taxed directly on his or her pro rata share of the income and gain attributable to the assets of the Trust and entitled to claim his or her pro rata share of the deductions and expenses attributable to the assets of the Trust. The income of the Trust is deemed to have been received or accrued by each unitholder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

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NOTES TO FINANCIAL STATEMENTS—Continued

The deductions of the Trust consist of severance taxes and administrative expenses. In addition, each unitholder is entitled to depletion deductions because the Net Profits Interest constitutes “economic interests” in oil and natural gas properties for federal income tax purposes. Each unitholder is entitled to amortize the cost of the Trust Units through cost depletion over the life of the Net Profits Interest or, if greater, through percentage depletion. Unlike cost depletion, percentage depletion is not limited to a unitholder’s depletable tax basis in the Trust Units. Rather, a unitholder could be entitled to percentage depletion as long as the applicable Underlying Properties generate net income.

Some Trust Units are held by a middleman, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a custodian in street name). 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, 16^th Floor, Houston, Texas 77002, telephone number (512) 236-6545, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.permianvilleroyaltytrust.com. Notwithstanding the foregoing, the middlemen holding units on behalf of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose 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.

The tax consequences to a unitholder of ownership of Trust Units will depend in part on the unitholder’s tax circumstances. Unitholders should consult their tax advisors about the federal tax consequences relating to owning the Trust Units.

State Taxes

The Trust’s revenues are from sources in the states of Louisiana, New Mexico and Texas. Because it distributes all of its net income to unitholders, the Trust is not taxed at the trust level in Louisiana or New Mexico. Although the Trust does not owe tax, the Trustee is required to file a return with Louisiana reflecting the income and deductions of the Trust attributable to properties located in that state. Louisiana and New Mexico presently have income taxes which tax income of nonresidents from real property located within that state. Louisiana and New Mexico also impose a corporate income tax which may apply to unitholders organized as corporations.

Texas imposes a franchise tax at a rate of 0.75% on gross revenues less certain deductions for returns originally due on or after January 1, 2016, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from designated passive sources, including royalties from mineral properties and other income from other non-operating mineral interests, and do not receive more than 10% of their income from operating an active trade or business, generally are exempt from the Texas franchise tax as “passive entities.” Although the Trust is intended to be exempt from Texas franchise tax at the trust level as a passive entity, each unitholder that is considered a taxable entity under the Texas franchise tax would generally be required to include its portion of Trust net income in its own Texas franchise tax computation.

Each unitholder should consult his or her own tax advisor regarding state tax requirements, if any, applicable to such person’s ownership of Trust Units.

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NOTES TO FINANCIAL STATEMENTS—Continued

7.       DISTRIBUTIONS TO UNITHOLDERS

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, subject to adjustments for changes made by the Trustee during the month in any cash reserves established for future liabilities of the Trust. Distributions are made to the holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) and are payable on or before the tenth business day after the record date.

The following table provides information regarding the Trust’s distributions paid during the periods indicated: