FORM 10-K

 UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 Washington, D.C. 20549

 FORM 10-K

 (Mark One)

 ANNUAL REPORT PURSUANT
 TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the fiscal year ended December 31,
2023

 or

 TRANSITION REPORT PURSUANT
 TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 For the transition period from
 to

 Commission File Number 001-35333

 PERMIANVILLE
ROYALTY TRUST

 (Exact name of registrant as specified in its
charter)

 Delaware

 45-6259461

 (State or other jurisdiction
 of

 incorporation or organization)

 (I.R.S. Employer

 Identification No.)

 The Bank of New York Mellon Trust Company, N.A., Trustee

 601 Travis Street

 16 th Floor

 Houston, Texas

 77002

 (Address of principal executive
 offices)

 (Zip Code)

 Registrant's telephone number, including
area code: (512) 236-6555

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

 Title
 of each class

 Trading
 Symbol(s)

 Name
 of each exchange on which registered

 Units of Beneficial Interest

 PVL

 New York Stock Exchange

 Securities
registered pursuant to Section 12(g) of the Act: None

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

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

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 No

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 (§232.405 of this chapter) 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.

 Large accelerated filer

 Accelerated filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

 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
has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that
prepared or issued its audit report.

 If
securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of
the registrant included in the filing reflect the correction of an error to previously issued financial statements.

by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation
received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).

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

 The aggregate market value of the voting and
non-voting common equity held by non-affiliates (25,482,058 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 $63,705,145.

 As of March 22, 2024, 33,000,000 Units of
Beneficial Interest of the Trust were outstanding.

 Documents
Incorporated By Reference: None

 Forward-Looking
 Statements

 ii

 Glossary
 of Certain Oil and Natural Gas Terms

 iv

 Item
 1.

 Business

 Item
 1A.

 Risk
 Factors

 Item
 1B.

 Unresolved
 Staff Comments

 Item
 1C.

 Cybersecurity

 Item
 2.

 Item
 3.

 Legal
 Proceedings

 Item
 4.

 Mine
 Safety Disclosures

 Item
 5.

 Market
 for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

 Item
 6.

 [Reserved]

 Item
 7.

 Trustee's
 Discussion and Analysis of Financial Condition and Results of Operations

 Item
 7A.

 Quantitative
 and Qualitative Disclosures About Market Risk

 Item
 8.

 Financial
 Statements and Supplementary Data

 Item
 9.

 Changes
 in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item
 9A.

 Controls
 and Procedures

 Item
 9B.

 Other
 Information

 Item
 9C.

 Disclosures
 Regarding Foreign Jurisdictions that Prevent Inspections

 Item
 10.

 Directors,
 Executive Officers and Corporate Governance

 Item
 11.

 Executive
 Compensation

 Item
 12.

 Security
 Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

 Item
 13.

 Certain
 Relationships and Related Transactions, and Director Independence

 Item
 14.

 Principal
 Accountant Fees and Services

 Item
 15.

 Exhibit and
 Financial Statement Schedules

 Item
 16.

 Form 10-K
 Summary

 SIGNATURES

 i

 FORWARD-LOOKING STATEMENTS

 This Annual Report on Form 10-K (this "Form 10-K")
includes "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" in Part II, Item 7 of this Form 10-K and "Risk Factors" in Part I, Item
1A of this Form 10-K regarding the financial position, business strategy, production and reserve growth, expected capital expenditures,
and other plans and objectives for the future operations of COERT Holdings 1 LLC ("COERT" or the "Sponsor") and
regarding future matters relating to Permianville Royalty Trust (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. Such expectations
may not 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:

 risks associated with
 the drilling and operation of oil and natural gas wells;

 the amount of future
 direct operating expenses and development expenses;

 the occurrence or threat
 of epidemic or pandemic diseases, such as the COVID-19 pandemic, or any government response
 to such occurrence or threat;

 the impact of geopolitical
 developments and tensions, war and uncertainty involving or in the geographical region of
 oil producing countries (including the ongoing armed conflicts between Russia and Ukraine
 and between Israel and Hamas and any related political or economic responses and counter-responses
 or otherwise by various global actors or the general effect on the global economy);

 global economic conditions,
 such as a general slowdown in the global economy, supply chain disruptions, inflationary
 pressures, currency fluctuations, changes in interest rates, and instability of financial
 institutions;

 the effects of actions
 by, or disputes among or between members of the Organization of Petroleum Exporting Countries
 ("OPEC") and other oil-exporting nations with respect to production levels or
 other matters related to the prices of oil and natural gas;

 the effect of existing
 and future laws and regulatory actions;

 the effect of changes
 in commodity prices or alternative fuel prices;

 the prohibition on
 the Trust's entry into any new hedging arrangements under the terms of the Conveyance;

 conditions in the capital
 markets;

 competition from others
 in the energy industry;

 uncertainty of estimates
 of oil and natural gas reserves and production;

 potential impacts on
 the Sponsor's business resulting from climate change, greenhouse gas regulations, and
 the impact of climate change related changes in the frequency and severity of weather patterns;
 and

 ii

 other risks described
 under the caption "Risk Factors" in Part I, Item 1A of this Form 10-K.

 Trust 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" in Part I, Item 1A of this Form 10-K. 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.

 iii

 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.

 iv

 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.

 v

 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.

 vi

 Item 1.
 Business.

 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 (as amended
and restated, and as further amended, 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 holders of 75% to holders of 50% of the outstanding Trust Units. 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.

 On August 31, 2018, COERT Holdings 1 LLC
("COERT" or the "Sponsor") acquired the Underlying Properties and all of the outstanding Trust Units owned by
Enduro (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.

 On May 3, 2023, the Sponsor notified the
Trustee that the Sponsor had entered into an agreement to divest certain acreage and associated production in the Permian Basin (the
 "2023 Divestiture Properties") that constituted part of the Underlying Properties and were therefore burdened by the Trust's
Net Profits Interest, for a total purchase price of approximately $6.7 million. On July 19, 2023, at a special meeting of Trust
unitholders, the unitholders approved the foregoing transaction and the release of the Trust's Net Profits Interest in the 2023
Divestiture Properties. On August 9, 2023, the Sponsor completed the sale of the 2023 Divestiture Properties, and the Trustee, on
behalf of the Trust, reconveyed, terminated and released to the Sponsor the Net Profits Interest with respect to the 2023 Divestiture
Properties. For additional information regarding this transaction, see "Trustee's Discussion and Analysis of Financial Condition
and Results of Operations—Sale of 2023 Divestiture Properties" in Part II, Item 7 of this Form 10-K.

 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:

 collecting cash attributable
 to the Net Profits Interest;

 paying expenses, charges
 and obligations of the Trust from the Trust's assets;

 distributing distributable
 cash to the Trust unitholders;

 causing to be prepared
 and distributed a tax information report for each Trust unitholder and preparing and filing
 tax returns on behalf of the Trust;

 causing to be prepared
 and filed reports required to be filed under the Securities Exchange Act of 1934, as amended
 (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;

 causing to be prepared
 and filed a reserve report by or for the Trust by independent reserve engineers as of December 31
 of each year in accordance with criteria established by the Securities and Exchange Commission
 (the "SEC");

 establishing, evaluating
 and maintaining a system of internal control over financial reporting in compliance with
 the requirements of the Sarbanes-Oxley Act of 2002;

 enforcing the Trust's
 rights under certain agreements; and

 taking any action it
 deems necessary or advisable to best achieve the purposes of the Trust.

 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. In addition, the Trustee 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 also may cause the Trust to mortgage its assets to secure payment of the indebtedness.
The terms of such indebtedness and security interest, if the Trustee, Delaware Trustee or an affiliate thereof were to loan funds, 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 if the Trust's 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.

 In November 2021, the Trustee notified COERT
of the Trustee's intent to build a cash reserve for the payment of future known, anticipated or contingent expenses or liabilities
of the Trust. From February 2022 through March 2023, the Trustee withheld $37,833, and commencing with the distribution to
Trust unitholders paid in April 2023 has been withholding and in the future intends to withhold $50,000, from the funds otherwise
available for distribution each month to gradually build a cash reserve of approximately $2.3 million. The Trustee may increase or decrease
the targeted cash reserve amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash
reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the Trust
Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent
expenses or liabilities eventually will be distributed to Trust unitholders, together with interest earned on the funds. As of December 31,
2023, this cash reserve totaled $941,386.

 Each month, after paying Trust obligations and
expenses, the Trustee distributes to the Trust unitholders any 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:

 interest-bearing obligations
 of the United States government;

 money market funds
 that invest only in United States government securities;

 repurchase agreements
 secured by interest-bearing obligations of the United States government; or

 bank certificates of
 deposit.

 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:

 the Trust, upon approval
 of the holders of at least 75% of the outstanding Trust Units, sells the Net Profits Interest;

 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 holders of at least
 75% of the outstanding Trust Units vote in favor of dissolution; or

 the Trust is judicially
 dissolved.

 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 that the Sponsor receives.

 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 each of these purchasers during
the periods presented:

 2023

 2022

 Phillips 66

 %

 %

 Pioneer Natural
 Resources USA

 %

 %

 Occidental Petroleum

 %

 %

 Competition and Markets

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

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

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

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

 Description of Trust Units

 Each Trust Unit is a unit of beneficial interest
in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis. Each Trust unitholder has the same rights
regarding his or her Trust Units as every other Trust unitholder has regarding his or her units. The Trust Units are in book-entry form
only and are not represented by certificates. The Trust had 33,000,000 Trust Units outstanding as of March 22, 2024.

 Distributions and Income Computations

 Each month, the Trustee determines the amount
of funds available for distribution to the Trust unitholders. Available funds are the excess cash, if any, received by the Trust from
the Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust's
liabilities for that month. Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.
The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to
monthly distributions payable on or before the 10th business day after the record date. If 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 Trust unitholders, in which case the Trust unitholders who called the
meeting are responsible for all such costs. Meetings must be held in such location as the Trustee designates in the notice of such meeting.
The Trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the Trust unitholders at
least 20 days and not more than 60 days before the meeting. Trust unitholders representing a majority of Trust Units outstanding
must be present or represented by proxy to have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned. Abstentions
and broker non-votes will not be deemed to be a vote cast.

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

 dissolve the Trust;

 amend the Trust Agreement
 (except with respect to certain matters that do not adversely affect the rights of Trust
 unitholders in any material respect); or

 approve the sale of
 all the assets of the Trust (including the sale of the Net Profits Interest).

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

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

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

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

 with the exception
 of certain costs and expenses related to 20 wells located in the Haynesville Shale identified
 in the Conveyance, all costs for (i) drilling, development, production and abandonment
 operations, (ii) all direct labor and other services necessary for drilling, operating,
 producing and maintaining the Underlying Properties and workovers of any wells located on
 the Underlying Properties, (iii) treatment, dehydration, compression, separation and
 transportation, (iv) all materials purchased for use on, or in connection with, any
 of the Underlying Properties and (v) any other operations with respect to the exploration,
 development or operation of hydrocarbons from the Underlying Properties;

 all losses, costs,
 expenses, liabilities and damages with respect to the operation or maintenance of the Underlying
 Properties for (i) defending, prosecuting, handling, investigating or settling litigation,
 administrative proceedings, claims, damages, judgments, fines, penalties and other liabilities,
 (ii) the payment of certain judgments, penalties and other liabilities, (iii) the
 payment or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying
 with applicable local, state and federal statutes, ordinance, rules and regulations,
 (v) tax or royalty audits and (vi) any other loss, cost, expense, liability or
 damage with respect to the Underlying Properties not paid or reimbursed under insurance;

 all taxes, charges
 and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate,
 franchise and like taxes) with respect to the ownership of, or production of hydrocarbons
 from, the Underlying Properties;

 all insurance premiums
 attributable to the ownership or operation of the Underlying Properties for insurance actually
 carried with respect to the Underlying Properties, or any equipment located on any of the
 Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;

 all amounts and other
 consideration for (i) rent and the use of or damage to the surface, (ii) delay
 rentals, shut-in well payments, minimum royalties and similar payments and (iii) fees
 for renewal, extension, modification, amendment, replacement or supplementation of the leases
 included in the Underlying Properties;

 all amounts charged
 by the relevant operator as overhead, administrative or indirect charges specified in the
 applicable operating agreements or other arrangements covering the Underlying Properties
 or operations with respect thereto;

 to the extent that
 the Sponsor is the operator of certain of the Underlying Properties and there is no operating
 agreement covering such portion of the Underlying Properties, those overhead, administrative
 or indirect charges that are allocated by the Sponsor to such portion of the Underlying Properties;

 if, as a result of
 the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of
 hydrocarbons produced from the Underlying Properties, any amounts previously credited to
 the determination of the net profits are reclaimed from the Sponsor, then the amounts reclaimed;

 all costs and expenses
 for recording the Conveyance and, at the applicable times, terminations and/or releases thereof;

 amounts previously
 included in gross profits but subsequently paid as a refund, interest or penalty; and

 at the option of the
 Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved
 development expenditure projects, including well drilling, recompletion and workover costs,
 which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to
 the limitations described below (provided that such costs shall not be debited from gross
 profits when actually incurred).

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

 Additional Provisions

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

 any proceeds that are
 withheld for any reason (other than at the request of the Sponsor) are not considered received
 until such time that the proceeds are actually collected;

 amounts received and
 promptly deposited with a non-affiliated escrow agent will not be considered to have been
 received until disbursed to the Sponsor by the escrow agent; and

 amounts received and
 not deposited with an escrow agent will be considered to have been received.

 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 no more
than 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 May 2023, the Sponsor sold approximately $0.3 million in non-producing, non-cash flowing acreage to a private oil company, free
and clear of the Net Profits Interest, as permitted under the Trust Agreement. The proceeds from this sale attributable to the Trust's
Net Profits Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

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

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

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

 U.S. Federal Income Tax Matters

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

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

 Classification and Taxation of the Trust

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

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

 Under
current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal
U.S. federal income tax rate applicable to long-term capital gai ns (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:

 obtain permits to conduct
 regulated activities;

 limit or prohibit
 drilling activities on certain lands lying within wilderness, wetlands and other protected
 areas;

 restrict the types,
 quantities and concentration of materials that can be released into the environment in the
 performance of drilling, completion and production activities;

 initiate investigatory
 and remedial measures to mitigate pollution from former or current operations, such as restoration
 of drilling pits and plugging of abandoned wells; and

 apply specific health
 and safety criteria addressing worker protection.

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

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

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

 The Sponsor also generates solid and hazardous
wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended ("RCRA"), and comparable
state statutes. RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes.
In the course of its operations, The Sponsor generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be classified
as hazardous wastes under RCRA and comparable state laws. Drilling fluids, produced waters, and most of the other wastes associated with
the exploration, production, and development of crude oil or natural gas are currently regulated under RCRA as non-hazardous wastes.
While many exploration and production wastes are exempt from regulation as hazardous waste, these wastes are generally subject to non-hazardous
waste regulation under RCRA and applicable state regulations. Many state governments have specific regulations and guidance for exploration
and production wastes, including the wastes associated with hydraulic fracturing activities.

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

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

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

 How the EPA and the USACE define "waters
of the United States" ("WOTUS"), which defines the extent of geographic jurisdiction under the CWA, can impact the
Sponsor's regulatory and permitting obligations under the CWA. In 2023, the EPA and the USACE issued a final rule (the "2023
rule") that is described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S. Supreme Court
decisions and guidance issued by the EPA and USACE interpreting the decisions. Shortly thereafter, the Supreme Court issued its decision
in Sackett II which overturned a substantial portion of the basis for the 2023 Rule. USACE and the EPA subsequently amended the 2023
rule and excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding
the sufficiency of the agencies' interpretation of the Sackett II decision. The Sponsor's regulatory obligations and permitting
costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the
ongoing litigation.

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

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

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

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

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

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

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

 The EPA is also charged with establishing National
Ambient Air Quality Standards ("NAAQS"), the implementation of which can indirectly impact the Sponsor's operations.
The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare.
This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75
to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone
standard. More recently, however, in February 2024, the EPA announced a final rule that will lower the annual standard for
fine particulate matter from 12 micrograms per cubic meter to 9 micrograms per cubic meter.

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

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

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

 The IRA included new Clean Air Act section 136(c) directing
the EPA to collect the Waste Emissions Charge from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide
equivalent emissions in a calendar year. The charge will first apply to methane emissions from calendar year 2024. The charge is determined
by comparing actual reported methane emissions to statutorily established "methane intensity figures" that are based on gas
production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility's allowable emissions
based on the applicable methane intensity figure. The charge will be $900 per ton for 2024 emissions, and will increase to $1,200 and
then $1,500 per ton in subsequent years. The program includes key exemptions, most notably a regulatory compliance exemption that applies
to and exempts the emissions from facilities that are subject to and in complete compliance with EPA's new or existing source methane
requirements. The EPA proposed new rules to implement the Waste Emissions Charge program in January 2024.

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

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

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

 National
Environmental Policy Act. The National Environmental Policy Act ("NEPA") requires the federal government to undertake
an environmental review prior to making a decision on most proposed federal actions – such as permits, leases, and rights-of-way. The
Trump Administration significantly revised the regulations implementing NEPA in 2020 in an effort to make the review process more efficient
and more narrowly tailored to the agency's specific action. The Biden Administration undertook an initial revision to the
NEPA regulations which were finalized in 2022, essentially reverting to the pre-2020 rule language for a few elements of the rules.
In 2023, the Biden Administration issued a second proposed rule that would make significant changes to the Trump Administration
regulations. The proposed rule is expected to be finalized in April 2024. In addition, in early 2023 the White House Council
on Environmental Quality issued Guidance to the federal agencies on how agencies should consider greenhouse gas emissions and climate
impacts in the course of their reviews under NEPA. Although the Trump Administration regulations were never fully implemented, the Biden
Administration changes may have a meaningful impact on federal reviews related to the Sponsor, especially as those reviews relate to
climate and environmental justice.

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

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

 Where You Can Find Other Information

 The Trust maintains a website at
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  In addition, the Trust will provide electronic copies of its recent filings free of charge
to the Trust unitholders upon request to the Trustee.

 Item 1A.
 Risk Factors.

 Summary of Risk Factors

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

 Business and Operating Risks

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

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

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

 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.

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

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

 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 distribution
 to Trust unitholders.

 Financial Risks

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

 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.

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

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

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

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

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

 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.

 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.

 Risks Related to the Structure of the Trust

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

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

 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.

 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.

 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.

 Trust unitholders
 have limited ability to enforce provisions of the Conveyance, and the Sponsor's liability
 to the Trust is limited.

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

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

 Risks Related to Ownership of the Trust Units

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

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

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

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

 Legal, Environmental and Regulatory Risks

 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 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.

 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.

 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.

 Cybersecurity Risks

 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 or the Trustee's
 operations.

 Tax Risks Related to the Trust Units

 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.

 Trust 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.

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

 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.

 BUSINESS AND OPERATING RISKS

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

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

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

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

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

 the armed conflicts
 between Russia and Ukraine and between Israel and Hamas and the potential destabilizing effects
 such conflicts may pose for the global oil and gas markets;

 the actions of OPEC,
 its members and other oil-producing nations, such as Russia, relating to oil price and production
 levels, including announcements of potential changes to such levels;

 the levels of production
 of oil and natural gas of non-OPEC countries;

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

 weather conditions
 and seasonal trends;

 technological advances
 affecting energy consumption and energy supply;

 U.S. and worldwide
 economic conditions;

 the occurrence or threat
 of epidemic or pandemic diseases, such as the COVID-19 pandemic, or any government response
 to such occurrence or threat;

 the price and availability
 of alternative fuels;

 the proximity, capacity,
 cost and availability of gathering and transportation facilities;

 the volatility and
 uncertainty of regional pricing differentials;

 governmental regulations
 and taxation;

 energy conservation
 and environmental measures; and

 acts of force majeure.

 These factors and the volatility of the energy
markets make it extremely difficult to predict future oil and natural gas price movements with any certainty. Commodity prices displayed
dramatic volatility in 2020, when the COVID-19 pandemic and various governmental actions taken to mitigate the impact of COVID-19
resulted in an unprecedented decline in demand for oil and natural gas. The effects of the economic disruption caused by the governmental
responses to the COVID-19 pandemic continued to be felt through 2023, in the form of lingering supply chain disruptions, higher inflation
and higher interest rates, which affected supply and demand for oil and natural gas. Meanwhile, as strains or variants of COVID-19
resurge, or if other epidemic or pandemic diseases or other public health event were to occur, the negative impact to global demand for
oil and natural gas could be material.

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

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

 The Sponsor has not entered into any hedge contracts
relating to oil and natural gas volumes expected to be produced on behalf of the Trust, and the terms of the Conveyance 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 cash available for distribution may be subject to 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 from
the Underlying Properties could vary both positively and negatively and in material amounts from estimates. Furthermore, direct operating
expenses and development expenses relating to the Underlying Properties could be substantially higher than current estimates. Petroleum
engineers are required to make subjective estimates of underground accumulations of oil and natural gas based on factors and assumptions
that include:

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

 oil and natural gas
 prices, production levels, Btu content, production expenses, transportation costs, severance
 and excise taxes and development expenses;

 the availability of
 enhanced recovery techniques;

 relationships with
 landowners, operators, pipeline companies and others; and

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

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

 The reserve report estimating the Trust's
proved reserves, future production and income attributable to the Trust's interests in the Underlying Properties as of December 31,
2023 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, 2023 as required by the SEC. The applicable prices for 2023 were $78.22 per Bbl of oil
and $2.637 per Mcf of natural gas.

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

 OPEC is an intergovernmental
organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those
taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain
other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices OPEC members
and other oil exporting nations might not agree to future production cuts or other actions to support and stabilize oil prices, and they
may not reduce oil prices or increase production in the future. Uncertainty regarding future actions that OPEC members or other oil exporting
countries may take could lead to continued volatility in the price of oil, which could adversely affect the financial condition and economic
performance of the operators of the Underlying Properties and may reduce the net proceeds to which the Trust is entitled, which could
materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders.

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

 As of December 31, 2023, 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 and therefore,
proceeds payable to the Trust and, ultimately, cash available for distribution to Trust unitholders. Further, none of the third-party
operators of the Underlying Properties is obligated to undertake any development activities, so any development and production activities
will be subject to their reasonable discretion. Therefore, the success and timing of drilling and development activities on properties
operated by the third-party operators depend on factors that are largely outside of the Sponsor's control, including:

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

 the availability of
 suitable drilling equipment, production and transportation infrastructure and qualified operating
 personnel;

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

 approval
 of other participants in drilling wells;

 the
 selection of technology;

 the
 selection of counterparties for the sale of production; and

 the
 rate of production of the reserves.

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

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

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

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

 declines
 in oil or natural gas prices;

 delays imposed by or
 resulting from compliance with environmental and other governmental or regulatory requirements,
 including permitting;

 unusual
 or unexpected geological formations;

 shortages
 of or delays in obtaining equipment and qualified personnel;

 lack of available gathering,
 transportation and processing facilities, including availability on commercially reasonable
 terms, or delays in construction of gathering facilities;

 lack
 of available capacity on interconnecting transmission pipelines;

 equipment
 malfunctions, failures or accidents;

 unexpected
 operational events and drilling conditions;

 market
 limitations for oil or natural gas;

 pipe
 or cement failures;

 casing
 collapses;

 lost
 or damaged drilling and service tools;

 loss
 of drilling fluid circulation;

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

 blowouts,
 explosions, fires and natural disasters;

 environmental hazards,
 such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases or other
 pollutants into the surface or subsurface environment;

 adverse
 weather conditions; and

 oil
 or natural gas property title problems or legal disputes regarding leasehold rights.

 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, 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,
future distributions to Trust unitholders may be reduced.

 Shortages of equipment, services and qualified
personnel could increase costs of developing and operating the Underlying Properties and reduce the amount of cash available for distribution
to 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 that they currently have planned for the Underlying Properties, which would reduce the amount of cash received by the Trust
and available for distribution to Trust unitholders.

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

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

 Adverse developments in Texas, Louisiana
or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount of cash
available for distribution 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 geographic
diversification, adverse developments in exploration and production of oil and natural gas in any of these areas of operation could have
a significantly greater impact on the results of operations and cash flows of the Underlying Properties than if the operations were more
diversified.

 FINANCIAL RISKS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

 The Sponsor maintains insurance coverage against
potential losses that it believes is customary in its industry. COERT 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.

 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, other than its
general liability and excess liability insurance policies that may cover third-party claims related to hydraulic fracturing operations
in accordance with, and subject to, the terms of such policies. These policies may not cover fines, penalties or costs and expenses related
to government-mandated cleanup of pollution. In addition, these policies do not provide coverage for all liabilities, and the insurance
coverage may not be adequate to cover claims that may arise; moreover, the Sponsor may not be able to maintain adequate insurance at
rates it considers reasonable. The occurrence of an event not fully covered by insurance could result in a significant decrease in the
amount of cash available for distribution by the Trust. The Trust does not maintain any type of insurance against any of the risks of
conducting oil and gas exploration and production, hydraulic fracturing operations, or related activities.

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

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

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

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

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

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

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

 The Sponsor and the Trust believe that, in a bankruptcy
of the Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as such, outside of the
Sponsor's bankruptcy estate. However, if the bankruptcy court were to hold otherwise, or if Louisiana or New Mexico law were held
to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and used to satisfy obligations to creditors
of the Sponsor, in which case the Trust would be an unsecured creditor of the Sponsor at risk of losing the entire value of the Net Profits
Interest to senior creditors.

 RISKS RELATED TO THE STRUCTURE OF THE TRUST

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

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

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

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

 In
addition, the Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest associated
with any lease that accounts for no more than 0.25% 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 may 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. For example, in May 2023, the Sponsor sold approximately $0.3 million in non-producing,
non-cash flowing acreage to a private oil company, free and clear of the Net Profits Interest, as permitted under the Trust Agreement.
The proceeds from this sale attributable to the Trust's Net Profits Interest were included in the distribution that was paid to
Trust unitholders on August 14, 2023.

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

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

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

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

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

 The Sponsor's
 interests may conflict with those of the Trust and the Trust unitholders in situations involving
 the development, maintenance, operation or abandonment of certain wells on the Underlying
 Properties for which the Sponsor acts as the operator. The Sponsor also may make decisions
 with respect to development expenses that adversely affect the Underlying Properties. These
 decisions include reducing development expenses on properties for which the Sponsor acts
 as the operator, which could cause oil and natural gas production to decline at a faster
 rate and thereby result in lower cash distributions by the Trust in the future.

 The Sponsor may sell
 some or all the Underlying Properties without taking into consideration the interests of
 the Trust unitholders. Such sales may not be in the best interests of the Trust unitholders.
 These purchasers may lack the Sponsor's experience or its creditworthiness. The Sponsor
 also has the right, under certain circumstances, to cause the Trustee to release all or a
 portion of the Net Profits Interest in connection with a sale of a portion of the Underlying
 Properties to which such Net Profits Interest relates. In such an event, the Trust is entitled
 to receive the fair value (net of sales costs) of the Net Profits Interest released.

 The Sponsor may sell
 its Trust Units without considering the effects such sale may have on Trust Unit prices or
 on the Trust itself. Additionally, the Sponsor can vote its Trust Units in its sole discretion
 without considering the interests of the other Trust unitholders. The Sponsor is not a fiduciary
 with respect to the Trust unitholders or the Trust and does not owe any fiduciary duties
 or liabilities to the Trust unitholders or the Trust.

 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 Conveyance, and the Sponsor's liability to the Trust is limited.

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

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

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

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

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

 RISKS RELATED TO OWNERSHIP OF THE TRUST UNITS

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

 Under the continued listing requirements of the
NYSE, a company will be considered to be out of compliance with the exchange's minimum price requirement if the company's
average closing price over a consecutive 30 trading day period ("Average Closing Price") is less than $1.00 (the "Minimum
Price Requirement"). Under NYSE rules, a company that is out of compliance with the Minimum Price Requirement has a cure
period of six months to regain compliance if it notifies the NYSE within 10 business days of receiving a deficiency notice of its intention
to cure the deficiency. A company may regain compliance if on the last trading day of any calendar month during the cure period the company
has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over the 30-trading-day period ending
on the last trading day of that month. If at the expiration of the cure period, both a $1.00 closing share price on the last trading
day of the cure period and a $1.00 average closing share price over the 30-trading-day period ending on the last trading day of the cure
period are not attained, the NYSE will commence suspension and delisting procedures. If delisted by the NYSE, a company's shares
may be transferred to the over-the-counter ("OTC") market, a significantly more limited market than the NYSE, which could
affect the market price, trading volume, liquidity and resale price of such shares. Securities that trade on the OTC markets also typically
experience more volatility compared to securities that trade on a national securities exchange. During the cure period, the company's
shares would continue to trade on the NYSE, subject to compliance with other continued listing requirements. The Trust has fallen out
of compliance with the Minimum Price Requirement in the past, most recently in 2020, and although the Trust was able to regain compliance
within the applicable grace period, the Trust may be unable to maintain compliance in the future and could again become subject to the
NYSE delisting procedures. Over the 30-day trading period that ended March 20, 2024, the closing price of the Trust Units on the
NYSE ranged from a high of $1.68 on February 8, 2024 to a low of $1.33 on March 20, 2024.

 T he 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.

 As
of March 22, 2024, the Sponsor holds an aggregate of 7,363,961 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. On June 22, 2022, pursuant to the
Registration Rights Agreement between the Trust and the Sponsor, the Trust filed a registration statement on Form S-3 registering
the offering by the Sponsor of 8,600,000 Trust Units. The registration statement was declared effective on July 7, 2022. Since
then, the Sponsor has sold approximately 1.2 million Trust Units under the Registration Statement pursuant to a Rule 10b5-1 trading
plan adopted in accordance with Rule 10b5-1 of the Exchange Act.

 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.

 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.

 LEGAL, ENVIRONMENTAL AND REGULATORY RISKS

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

 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 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 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.

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

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

 The IRA included new
Clean Air Act section 136(c) directing EPA to collect the Waste Emissions Charge from facilities in the oil and gas sector that
report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year. The charge will first apply to methane emissions
from calendar year 2024. The charge is determined by comparing actual reported methane emissions to statutorily established "methane
intensity figures" that are based on gas production or throughput, with a charge assessed for every ton of methane emissions that
exceeds the facility's allowable emissions based on the applicable methane intensity figure. The charge will be $900 per ton for
2024 emissions and will increase to $1,200 and then $1,500 per ton in subsequent years. The program includes key exemptions, most notably
a regulatory compliance exemption that applies to and exempts the emissions from facilities that are subject to and in complete compliance
with the EPA's new or existing source methane requirements. The EPA proposed new rules to implement the Waste Emissions Charge
program in January 2024.

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

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

 In addition, new and emerging regulatory initiatives
in the U.S. related to climate change could adversely affect the Trust. On March 6, 2024, the SEC issued a final rule regarding
the enhancement and standardization of mandatory climate-related disclosures for investors. The final rule mandates extensive disclosure
of climate-related data, risks, and opportunities, including financial impacts, physical and transition risks, related governance and
strategy and greenhouse gas emissions, for certain public companies. Compliance with the final rule may result in increased legal,
accounting and financial compliance costs, make some activities more difficult, time-consuming and costly, and place strain on the personnel,
systems and resources of the Sponsor or the Trust or both.

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

 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 adopted the Methane
Rule, which established requirements to control GHG emissions from oil and gas sources that are constructed, modified, or reconstructed
after September 18, 2015. More recently, on November 15, 2021, the EPA published a proposed rule that would establish
emissions guidelines for the control of methane from existing oil and gas sources for the first time under the CAA. The EPA intends to
adopt the existing source emissions guidelines as a final rule by the end of 2022, which would then trigger a requirement for states
to develop rules that will make the federal emissions guidelines enforceable as state rules over a three- to four-year period
The ultimate fate of the proposed methane emissions guidelines 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

 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.

 CYBERSECURITY RISKS

 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. 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.

 Trust 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, Trust 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 Trust 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 Trust 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.

 Item 1B.
 Unresolved Staff Comments.

 None.

 Item 1C.
 Cybersecurity.

 The Trust has no directors or executive officers.
The affairs of the Trust are managed by the Trustee. The Trust falls under the cybersecurity program of The Bank of New York Mellon Corporation
("BNY Mellon"), the parent corporation of The Bank of New York Mellon Trust Company, N.A. As further described in its 2023 Annual
Report, BNY Mellon maintains a broad range of defenses aimed at remaining abreast of and responding to evolving cybersecurity threats
impacting it, its operations, its clients, its third-party service providers and the broader financial services sector.

 Risk Management Strategy and Procedures

 BNY Mellon has implemented policies and procedures
designed to detect, prevent and respond to malicious and accidental disruptions to the delivery of critical technology services. BNY
Mellon's cybersecurity strategy and procedures are embedded in its Three Lines of Defense model.

 As part of its first line of defense, BNY Mellon
maintains a dedicated Information Security Division ("ISD"), led by the Chief Information Security Officer (the "CISO"),
that is responsible for the day-to-day management of risks from cybersecurity threats. ISD's responsibilities include cyber threat
intelligence, incident response and other cybersecurity operations aimed at enabling BNY Mellon to identify, assess and manage existing
and emerging cybersecurity threats. ISD monitors for potential threats and communicates relevant risks to the CISO and other members
of executive management. Additionally, ISD maintains a cybersecurity incident response and reporting process pursuant to which cybersecurity
incidents are classified according to their severity based upon an assessment of multiple factors. Certain cybersecurity incidents may
activate enterprise-wide resiliency processes, which include, among other things, escalation through the management and Board committee
structures described below. BNY Mellon also has standing arrangements with third parties to assist BNY Mellon in identifying, assessing
and managing cybersecurity threats, including in connection with risk assessments, penetration testing, legal advice and other aspects
of BNY Mellon's cybersecurity risk management and incident response processes.

 BNY Mellon has a defined third-party governance
framework to help manage the risk posed to it by the use of third-party service providers. BNY Mellon evaluates the risk posed by third-party
service engagements based on multiple factors. BNY Mellon has protocols that seek to mitigate cybersecurity risks associated with third-party
service providers based on the risk level assigned to such third party, which may include mandatory contractual obligations or the implementation
of additional controls by BNY Mellon and/or the applicable service provider.

 ISD is subject to ongoing review and challenge
from Technology Risk Management, which is a part of the independent second line of defense risk function. Technology Risk Management,
together with the broader Risk & Compliance group, is responsible for and manages BNY Mellon's risk management framework
and establishes guidance for ISD and management designed to help identify, assess and manage cybersecurity risk.

 BNY Mellon's Internal Audit function serves
as the third line of defense and provides an independent view on how effectively the organization as a whole manages cybersecurity risk.

 Risk Management Oversight and Governance

 BNY Mellon's management is responsible for
assessing and managing BNY Mellon's material risks from cybersecurity threats with oversight provided by its Board of Directors
(the "Board") and the Board committees. The Risk Committee of the Board has primary responsibility for oversight of the overall
operation of BNY Mellon's risk management framework, including policies and practices addressing cybersecurity risk, and is
responsible for the oversight of the second line of defense with respect to its cybersecurity risk management responsibilities. The Technology
Committee of the Board and the full Board regularly receive reports and briefings from management concerning cybersecurity matters, including
any significant changes to BNY Mellon's cybersecurity program. BNY Mellon also has protocols for escalating cybersecurity
threats and incidents to the Technology Committee of the Board and the full Board. In addition, the Audit Committee of the Board monitors
and oversees the performance of Internal Audit, including with respect to its cybersecurity risk management responsibilities.

 At the management level, BNY Mellon's Technology
Oversight Committee, which is the senior management committee responsible for the governance and oversight of BNY Mellon's significant
technology projects and initiatives, reviews reports from management concerning ISD and is responsible for, among other things, escalating
issues, including significant cybersecurity threats and incidents, to the Technology Committee of the Board. The Technology Oversight
Committee is chaired by the Chief Information Officer (the "CIO") and its members include the CISO.

 BNY Mellon's Technology Risk Committee is
responsible for, among other things, overseeing and reviewing significant cybersecurity incidents. The Technology Risk Committee receives
reports from management and has protocols for escalating certain issues and risks to the Senior Risk and Control Committee and the Risk
Committee of the Board. The Technology Risk Committee is co-chaired by the Head of Technology Risk and Control and the Chief Technology
Risk Officer, and the CISO is a member.

 BNY Mellon's CIO, CISO and Chief Technology
Risk Officer each have extensive experience in assessing and managing risks from cybersecurity threats. BNY Mellon's CISO joined
BNY Mellon in 2022 and previously served as head of information security at a Fortune 500 biopharmaceutical company and an information
technology company, as well as the Global Chief Technology Officer at a large cybersecurity company. BNY Mellon's CIO has served
in that position since 2017 and previously held roles as Chief Information Officer, Chief Technology Officer, and numerous other technology
management positions at other large financial institutions. BNY Mellon's Chief Technology Risk Officer joined BNY Mellon in 2021
and previously served as Global Head of Technology Risk Management, Chief Information Security Officer, Global Head of Cyber Risk and
Operational Resilience and Chief Risk Officer for Technology and Operations at other large financial institutions.

 Item 2.

 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, 2023, the Underlying Properties
had proved reserves of 7.9 MMBoe with 88% and 94% of the volumes and PV-10 value, respectively, attributable to proved developed reserves.
All of the 7.9 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,
2023, the Sponsor held average working interests of approximately 19% and 15% and average net revenue interests of approximately 16%
and 12% 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,
2023. 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, 2023 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, 2023 and 2022:

 Trust Net
 Profits Interest

 Underlying

 Oil (1)

 Natural Gas

 Total (2)

 PV-10 (3)

 Oil (1)

 Natural Gas

 Total (2)

 PV-10 (3)

 (MBbls)

 (MMcf)

 (MBoe)

 (in thousands)

 (MBbls)

 (MMcf)

 (MBoe)

 (in thousands)

 2023

 Proved Developed Producing

 1,826

 4,545

 2,584

 $
 62,512

 4,239

 10,481

 5,986

 $
 78,140

 Proved Developed Non-Producing

 3,162

 6,774

 4,984

 8,465

 Proved Undeveloped

 1,648

 7,370

 2,924

 1,039

 4,615

 2022

 Proved Developed Producing

 3,429

 6,893

 4,578

 $
 142,863

 7,888

 15,493

 10,470

 $
 178,578

 Proved Developed Non-Producing

 Proved Undeveloped

 1,591

 19,985

 2,328

 1,228

 24,751

 (1)
 Reserves
 for natural gas liquids are included as a component of oil reserves.

 (2)
 Boe
 represents an approximate energy equivalent basis such that one Bbl of crude oil equals approximately
 six Mcf of natural gas. However, the value of oil and natural gas value and the value of
 reserve volumes of oil and natural gas are often substantially different than the amount
 implied by the Boe ratio.

 (3)
 PV-10
 is a non-GAAP financial measure and represents the present value of estimated future cash
 inflows from proved crude oil and natural gas reserves, less future development and production
 costs, discounted at 10% per annum to reflect timing of future cash inflows using the twelve-month
 unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment
 for differentials in location and quality, for each of the preceding twelve months. An estimate
 of PV-10 is provided because it provides useful information to investors as it is widely
 used by professional analysts and sophisticated investors when evaluating oil and gas companies.
 PV-10 is considered relevant and useful for evaluating the relative monetary significance
 of oil and natural gas reserves. PV-10 is not intended to represent the current market value
 of the estimated reserves of the Underlying Properties. PV-10 differs from standardized measure
 of discounted future net cash flows because it does not include the effect of future income
 taxes. Please refer to the notes to the financial statements of the Trust included in this
 Form 10-K.

 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:

 2023

 2022

 2021

 Oil (per Bbl)

 $
 78.22

 $
 93.67

 $
 66.56

 Natural gas (per Mcf)

 $
 2.64

 $
 6.36

 $
 3.60

 Changes in Proved Undeveloped Reserves

 During
the year ended December 31, 2023, proved undeveloped reserves of the Underlying Properties decreased 0.2 MMBoe primarily due to
the decrease in the estimated reserves for the booked, non-operated wells in Haynesville shale of Louisiana, partially offset
by the increase in the amount of booked, non-operated Wolfcamp shale wells in the Permian Basin. The following is a summary of the changes
in quantities of proved undeveloped reserves for the Underlying Properties during the year ended December 31, 2023.

 Underlying

 Oil (1)

 Gas

 Total

 (MBbls)

 (MMcf)

 (MBoe)

 Balance – December 31, 2022

 2,328

 1,228

 Development

 2,924

 1,039

 Revisions and
 Other

 (840
)

 (2,328
)

 (1,228
)

 Balance – December 31, 2023

 2,924

 1,039

 (1) Reserves
for natural gas liquids are included as a component of oil reserves.

 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, 2023:

 Acres

 Gross

 Net

 Permian Basin

 119,112

 33,830

 East Texas/North Louisiana

 10,424

 2,840

 Total

 129,536

 36,670

 The following is a summary of the producing wells
on the Underlying Properties as of December 31, 2023:

 Oil

 Gas

 Gross
 Wells (1)

 Net Wells

 Gross Wells (1)

 Net Wells

 Permian Basin

 2,305

 East Texas/North Louisiana

 —

 —

 Total

 2,305

 (1)
 The Sponsor's total producing wells include 2,682
non-operated wells.

 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:

 2023

 2022

 2021

 Gross

 Net

 Gross

 Net

 Gross

 Net

 Permian Basin

 Development Wells:

 0.5

 0.1

 0.1

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 Exploratory Wells:

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 Total:

 0.5

 0.1

 0.1

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 2023

 2022

 2021

 Gross

 Net

 Gross

 Net

 Gross

 Net

 East Texas/North Louisiana

 Development
 Wells: (1)

 —

 —

 0.1

 0.1

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 Exploratory Wells:

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 Total:

 —

 —

 0.1

 0.1

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 —

 (1) Production
of natural gas liquids is immaterial and included as a component of natural gas production.

 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 61%
of the future production from the Underlying Properties is expected to be oil and approximately 39% 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 119,112 gross
(33,830 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, 2023). The largest field in the Permian Basin
region is the Spraberry field, which individually accounts for 32 percent of the Underlying Properties reserves as of December 31,
2023. This unit produces from the Wolfcamp formations at depths up to 8,500 feet. Proved reserves attributable to the Underlying Properties
in the Eunice Monument field were 2.6 MMBoe as of December 31, 2023. This field is operated by Pioneer Natural Resources, Ovintiv
and Franklin Mountain.

 East Texas/North Louisiana Region

 The Underlying Properties contain interests in
10,424 gross (2,840 net) acres in the East Texas/North Louisiana region across three fields: the Elm Grove field, operated primarily
by Aethon Energy Operating, LLC and Comstock Oil & Gas, LLC; and the Kingston field, operated by EXCO Resources and Diversified
Production, LLC. 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, 2023.

 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,
2023, 2022 and 2021.

 2023

 2022

 2021

 Permian Basin

 Oil Sales Volumes (Bbls)

 439,122

 495,434

 730,891

 Gas (1) Sales Volumes (Mcf)

 1,700,680

 1,980,171

 3,067,864

 Total Sales Volumes (Boe)

 722,568

 825,462

 1,242,202

 Oil Average Sales Price per Bbl

 $
 78.85

 $
 90.02

 $
 45.62

 Natural Gas Average Sales Price per Mcf

 $
 3.52

 $
 5.12

 $
 2.00

 Average Lease Operating Expense per Boe

 $
 30.44

 $
 25.42

 $
 20.55

 Proved Reserves (MBoe)

 6,830

 10,881

 10,876

 East Texas/North Louisiana

 Oil Sales Volumes (Bbls)

 1,132

 2,036

 Gas (1) Sales Volumes (Mcf)

 1,081,888

 1,377,062

 1,862,665

 Total Sales Volumes (Boe)

 180,733

 230,643

 312,480

 Oil Average Sales Price per Bbl

 $
 71.23

 $
 61.47

 $
 30.31

 Natural Gas Average Sales Price per Mcf

 $
 4.22

 $
 5.33

 $
 2.08

 Average Lease Operating Expense per Boe

 $
 8.61

 $
 8.18

 $
 7.63

 Proved Reserves (MBoe)

 1,112

 1,597

 Total

 Oil Sales Volumes (Bbls)

 439,540

 496,566

 732,927

 Gas (1) Sales Volumes (Mcf)

 2,782,568

 3,357,233

 4,930,529

 Total Sales Volumes (Boe)

 903,302

 1,056,105

 1,554,682

 Oil Average Sales Price per Bbl

 $
 78.84

 $
 89.96

 $
 45.65

 Natural Gas Average Sales Price per Mcf

 $
 3.79

 $
 5.21

 $
 2.03

 Average Lease Operating Expense per Boe

 $
 26.07

 $
 21.66

 $
 17.96

 Proved Reserves (MBoe)

 7,941

 11,708

 12,474

 (1) Production
of natural gas liquids is immaterial and included as a component of natural gas production.

 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 no more than 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 may 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 May 2023, the Sponsor sold approximately $0.3 million in non-producing, non-cash flowing acreage to a private oil company,
free and clear of the Net Profits Interest, as permitted under the Trust Agreement. The proceeds from this sale attributable to the Trust's
Net Profits Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

 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

 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:

 royalties
 and other burdens, express and implied, under oil and natural gas leases and other arrangements;

 overriding
 royalties, production payments and similar interests and other burdens created by the Sponsor's
 predecessors in title;

 a
 variety of contractual obligations arising under operating agreements, farm-out agreements,
 production sales contracts and other agreements that may affect the Underlying Properties
 or their title;

 liens
 that arise in the normal course of operations, such as those for unpaid taxes, statutory
 liens securing unpaid suppliers and contractors and contractual liens under operating agreements
 that are not yet delinquent or, if delinquent, are being contested in good faith by appropriate
 proceedings;

 pooling,
 unitization and communitization agreements, declarations and orders;

 easements,
 restrictions, rights-of-way and other matters that commonly affect property;

 conventional
 rights of reassignment that obligate the Sponsor to reassign all or part of a property to
 a third party if the Sponsor intends to release or abandon such property;

 preferential
 rights to purchase or similar agreements and required third party consents to assignments
 or similar agreements;

 obligations
 or duties affecting the Underlying Properties to any municipality or public authority with
 respect to any franchise, grant, license or permit, and all applicable laws, rules, regulations
 and orders of any governmental authority; and

 rights
 reserved to or vested in the appropriate governmental agency or authority to control or regulate
 the Underlying Properties and also the interests held therein, including the Sponsor's
 interests and the Net Profits Interest.

 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—Financial Risks—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 Part I, Item 1A of this Form 10-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—Financial Risks—The Trust Units may lose value as a result of title deficiencies
with respect to the Underlying Properties" in Part I, Item 1A of this Form 10-K.

 Item 3.
 Legal Proceedings.

 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.

 Item 4.
 Mine Safety Disclosures.

 Not applicable

 Item 5.
 Market for Registrant's
 Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

 The
Trust Units trade on the New York Stock Exchange under the symbol "PVL." At December 31, 2023, there were 33,000,000
Trust Units outstanding. On March 20, 2024, there were five 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 Trust unitholders, see Note 5 of the Notes to Financial Statements in Part II, 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, 2023.

 Purchases of Equity Securities

 There were no purchases of Trust Units by the
Trust or any affiliated purchaser during the fourth quarter of 2023.

 Item 6.
 [Reserved]

 Item 7.
 Trustee's Discussion and
 Analysis of Financial Condition and Results of Operations.

 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:

 oil
 and natural gas sales prices;

 volumes
 of oil and natural gas produced and sold attributable to the Underlying Properties;

 production
 and development costs;

 price
 differentials;

 potential
 reductions or suspensions of production;

 the
 amount and timing of Trust administrative expenses; and

 the
 establishment, increase, or decrease of reserves for approved development expenses or future
 liabilities of the Trust.

 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.

 2023 Recap and 2024 Outlook

 The average NYMEX oil and natural gas prices experienced
significant volatility in 2023, with the average NYMEX oil price declining from $94.57 per Bbl in calendar year 2022 to $77.65 per Bbl
in calendar year 2023, a decline of 18%. Meanwhile, the price range varied from a low of $66.74 per Bbl in March 2023 to a high
of $93.68 per Bbl in September 2023, before declining during the fourth quarter in response to increasing conflict in the Middle
East. Natural gas prices faced even greater challenges in 2023 after seeing some of the highest prices in prior years in 2022. The average
NYMEX natural gas price declined from $6.41 per MMBtu in calendar year 2022 to $2.54 per MMBtu in calendar year 2023, a decline of 60%.
Prices for natural gas experienced similar volatility, ranging from a low of $1.77 per MMBtu in June 2023 to a high of $3.77 per
MMBtu in January 2023. The year-over-year decline in commodity prices also drove a significant reduction in third-party operator
drilling activity on the Underlying Properties, which led to a 45% decrease in development expenses for the production months of 2023
compared to 2022.

 The Sponsor believes that the outlook for the
oil and gas industry remains mixed, with oil prices having ended 2023 within a range consistent with prior years, but with natural gas
prices currently facing levels generally below operator-targeted forward prices for capital deployment. In addition, mergers and acquisitions
have continued to change the makeup of the companies deploying capital in the sector. As larger public companies continue to acquire
smaller public companies and private operators, these larger companies are likely to react differently to commodity price volatility
than smaller operators have in historical cycles. This merger and acquisition activity has also affected the operators of the Underlying
Properties, with several of the largest and/or most active operators for the Underlying Properties announcing merger events in 2023.
Nevertheless, the capital spending activity or operating performance for the Underlying Properties under new third-party operatorship
in the future may not be consistent with such activity or performance experienced under previous third-party operators in prior years.

 As
discussed further under "—Sale of 2023 Divestiture Properties" below, the Sponsor leveraged the volatility in commodity
prices to negotiate and subsequently close the sale of certain acreage and associated production in the Permian Basin that constituted
part of the Underlying Properties, generating $0.146920 per Trust Unit of distributable proceeds from properties that in the prior
three years had generated cumulative net profits of $0.00831 per Trust Unit.

 Given the commodity price volatility as well as
the recent merger activity in the industry, the operators of the Underlying Properties continue to evaluate planned capital expenditures
during 2024. Based on currently available information, the Sponsor anticipates 2024 capital expenditures on the Underlying Properties
to range from $5.0 million to $9.0 million, or $4.0 million to $7.2 million net to the Trust's 80% Net Profits Interest.
This would represent a decrease from 2023 levels, partly due to lower projected natural gas prices, which could reduce capital activity
on the Haynesville area of the Underlying Properties, but somewhat offset by continued activity strength in the portion of the Underlying
Properties located in the Permian region. The expected range is also wider compared to 2023 given the volatility and recent third-party
operator merger activity. The Sponsor indicates that it continues to have access to adequate capital and liquidity to fund such capital
expenditures as they come due.

 In addition to continued capital expenditure participation,
the Sponsor believes there could be further opportunity in 2024 for prospective divestitures, as operators of some of the Underlying
Properties look to consolidate non-operated interests and acreage given recent merger and acquisition activity in the industry.

 Capex Drilling Activity Update

 Presented
below is a summary of the current status of certain notable capital projects recently undertaken on the Underlying Properties pursuant
to the capital expenditure program described above.

 The following table is not intended to be a comprehensive
list reflecting all capital expenditures to date. In addition, there can often be a several-month delay from the time of capital expenditures
to the time of production and cash flows attributable to the Underlying Properties, especially given the non-operated nature of
the Underlying Properties.

 Operator

 Region

 Number

 of Wells

 Underlying

 Working Interest

 Project

 Capex

 Cumulative

 Total

 (in thousands)

 Status

 Large Cap E&P 1

 Midland

 6.6
 %

 2,002

 2 Producing, Awaiting First Revenues; 3 Drilling
 In-Process

 Large Cap E&P 2

 Conventional Permian

 N/A
 (Field)

 0.8
 %

 New Drills / Workovers

 In-process/ Continual Program

 Large Private E&P

 Haynesville

 3.5
 %

 -

 Pre-Drill

 PE-Backed Private 1

 Delaware

 5.4
 %

 Producing Awaiting Revenues

 PE-Backed Private 2

 Delaware

 1.0
 %

 Drilling In-Process

 Large Cap E&P 3

 Delaware

 3.4
 %

 Drilling In-Process

 Large Cap E&P 4

 Conventional
Permian

 3.7
 %

 New Drills / Workovers

 Drilling In-Process

 T he
Sponsor expects that a majority of the projects above that are still in process or awaiting first revenues will be completed and
will begin producing during 2024.

 Sale of 2023 Divestiture Properties

 On May 3, 2023, the Sponsor notified the
Trustee that the Sponsor had entered into an agreement to divest certain acreage and associated production in the Permian Basin (the
 "2023 Divestiture Properties") that constituted part of the Underlying Properties and were therefore burdened by the Trust's
Net Profits Interest, for a total purchase price of approximately $6.7 million. On July 19, 2023, at a special meeting of Trust
unitholders, the unitholders approved the foregoing transaction and the release of the Trust's Net Profits Interest in the 2023
Divestiture Properties. On August 9, 2023, the Sponsor completed the sale of the 2023 Divestiture Properties, and the Trustee, on
behalf of the Trust, reconveyed, terminated and released to the Sponsor the Net Profits Interest with respect to the 2023 Divestiture
Properties. The total proceeds received by the Sponsor from the sale of the 2023 Divestiture Properties, after preliminary closing adjustments,
were approximately $6.5 million, inclusive of the escrow funded by the buyer and partial expense reimbursement associated with the
proxy solicitation. The Sponsor deducted the final transaction expenses from the sales proceeds, along with an escrow amount of $250,000
to cover possible indemnification obligations under the purchase and sale agreement (the "Indemnification Escrow Amount"),
to arrive at final net proceeds, based upon the Trust's Net Profits Interest.

 On September 20, 2023, the Trust announced
a special cash distribution to Trust unitholders of $0.069670 per Trust Unit, payable on October 13, 2023 to Trust unitholders of
record on October 2, 2023, reflecting 50% of the Trust's share of the net proceeds, after accounting for the Indemnification
Escrow Amount. The remaining 50% of the Trust's share of the net proceeds was temporarily retained by the Sponsor as a source of
payment of the Trust's proportionate share of any post-closing purchase price adjustments, with any amount remaining (less any
amounts in dispute) after such adjustments to be paid to the Trust within five business days after finalization of the settlement statement
and included in a distribution to Trust unitholders. On November 6, 2023, the Trust announced a special cash distribution to Trust
unitholders of $0.077250 per Trust Unit, payable on November 22, 2023 to Trust unitholders of record on November 16, 2023,
reflecting the remaining 50% of the Trust's share of the net proceeds (net of the Indemnification Escrow Amount). Within 12 months
after the closing of the sale, any remaining amount from the Indemnification Escrow Amount (less any amounts in dispute) will be released
to the Trust and included in a distribution to Trust unitholders.

 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, 2023 and 2022.

 Underlying Properties
 Sales Volumes

 Average
 Price

 Month of Distribution

 Oil
 (Bbls)

 Natural Gas
 (Mcf)

 Oil
 (per Bbl)

 Natural Gas
 (per
 Mcf)

 2023:

 January

 37,419

 250,486

 $
 94.66

 $
 7.20

 February

 36,796

 222,785

 $
 85.39

 $
 6.89

 March

 38,056

 217,262

 $
 80.01

 $
 5.19

 April

 34,720

 204,419

 $
 78.48

 $
 4.23

 May

 38,896

 191,223

 $
 75.01

 $
 4.71

 June

 39,651

 241,119

 $
 75.60

 $
 3.84

 July

 38,120

 195,616

 $
 71.94

 $
 2.85

 August

 64,721

 604,148

 $
 86.52

 $
 2.75

 September

 43,894

 204,848

 $
 71.99

 $
 1.32

 October

 33,806

 227,756

 $
 69.15

 $
 2.01

 November

 33,461

 222,906

 $
 73.07

 $
 2.02

 Total—2023 (1)

 439,540

 2,782,568

 $
 78.84

 $
 3.79

 Underlying Properties
 Sales Volumes

 Average
 Price

 2022:

 January

 40,878

 280,503

 $
 68.90

 $
 3.78

 February

 40,779

 214,181

 $
 78.30

 $
 4.28

 March

 44,180

 325,962

 $
 76.45

 $
 5.31

 April

 40,390

 290,847

 $
 73.25

 $
 4.96

 May

 47,114

 266,091

 $
 74.79

 $
 4.09

 June

 40,553

 331,076

 $
 86.55

 $
 5.00

 July

 40,102

 380,958

 $
 98.77

 $
 4.84

 August

 41,122

 301,477

 $
 105.29

 $
 4.52

 September

 37,350

 297,117

 $
 107.77

 $
 5.37

 October

 37,873

 287,116

 $
 110.92

 $
 6.85

 November

 43,632

 237,538

 $
 106.32

 $
 7.56

 December

 42,594

 144,367

 $
 97.06

 $
 7.05

 Total—2022

 496,567

 3,357,233

 $
 89.96

 $
 5.21

 (1)
 The year ended December 31, 2023 does not include sales volumes
 for December as the Trust did not make a distribution in that month, as the Net Profits
 Interest calculation for the corresponding production period was negative.

 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 Net Profits Interest. Net profits
income for the years ended December 31, 2023 and 2022 were determined as shown in the following table:

 2023

 2022

 Gross profits:

 Oil sales

 $
 34,653,097

 $
 44,669,834

 Natural gas sales

 10,555,426

 17,479,475

 Total

 45,208,523

 62,149,309

 Costs:

 Direct operating expenses:

 Lease operating expenses

 22,136,000

 21,914,000

 Compression, gathering and transportation

 1,696,000

 3,276,000

 Production, ad valorem and other taxes

 2,963,000

 4,750,000

 Development expenses

 6,729,000

 12,143,000

 Total

 33,524,000

 42,083,000

 Gross proceeds
 from sale/lease of undeveloped acreage

 306,250

 130,030

 Net profits attributable to Underlying

 $
 11,990,773

 $
 20,196,339

 Percentage allocable to Net Profits Interest

 %

 %

 Income from Net Profits Interest

 $
 9,592,619

 $
 16,157,071

 Capex Reserve – Release (Holdback) for anticipated 2022-2023
 capital expenditures

 1,000,000

 (1,000,000
)

 Less: Trust general and administrative
 expenses and cash withheld for expenses

 (1,327,790
)

 (1,676,571
)

 Distributable income generated by properties
 prior to divestiture

 $
 9,264,829

 $
 13,480,500

 Income from sale of Net Profits Interest

 4,848,281

 -

 Distributable income

 $
 14,113,110

 $
 13,480,500

 As reflected in the Net Profits Interest calculation
for November 2023, direct operating and development expenses exceeded revenues, thereby causing net profits attributable to the
Underlying Properties to be negative and resulting in a Net Profits Interest shortfall of approximately $1.2 million. As a result,
there was no distribution to Trust unitholders in the month of December 2023. The shortfall of $1.2 million was carried forward
to be deducted from future net profits to be generated by the Underlying Properties, and the corresponding revenues and associated direct
operating and development expenses are excluded from the calculation of distributable income for the year ended December 31, 2023
detailed in the table above as well as the related sales volumes detailed below. As a result, only eleven months of results are included
in the results for the year ended December 31, 2023.

 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, 2023 and 2022:

 2023

 2022

 Underlying Properties Sales Volumes:

 Oil (Bbls)

 439,540

 496,567

 Natural Gas (Mcf)

 2,782,568

 3,357,233

 Combined (Boe)

 903,301

 1,056,106

 Average Prices:

 Oil – NYMEX (applicable NPI period)
 ($/Bbl)

 $
 76.83

 $
 91.84

 Differential

 $
 2.01

 $
 (1.88
)

 Oil prices realized
 ($/Bbl)

 $
 78.84

 $
 89.96

 Natural gas – NYMEX (applicable
 NPI period) ($/Mcf)

 $
 2.26

 $
 5.85

 Differential

 $
 1.53

 $
 (0.64
)

 Natural gas
 prices realized ($/Mcf)

 $
 3.79

 $
 5.21

 Years Ended December 31, 2023 and 2022

 Net profits attributable to the Underlying Properties
for the year ended December 31, 2023 are calculated from the following:

 oil
 sales related to oil produced from the Underlying Properties primarily from September 2022
 through July 2023;

 natural
 gas sales related to natural gas produced from the Underlying Properties primarily from August 2022
 through June 2023; and

 direct
 operating and development expenses related to expenses and capital incurred primarily from
 October 2022 to August 2023.

 Net profits attributable to the Underlying Properties
for the year ended December 31, 2023 were $12.0 million compared to $20.2 million for the year ended December 31, 2022.
As discussed in "—Computation of Income from Net Profits Interest Received by the Trust" above, no distribution was
made to Trust unitholders in December 2023 due to the Net Profits Interest shortfall. Accordingly, under the modified cash basis
of accounting, the oil and natural gas sales, direct operating expenses and development expenses attributable to that period was not
included and instead will be included in the Trust's results once the shortfall is recouped. Therefore, several variances between
the periods are due to the inclusion of only eleven months of results in the year ended December 31, 2023 compared to twelve months
in the year ended December 31, 2022. The $8.2 million decrease in net profits attributable to the Underlying Properties from
the 2022 period to the 2023 period was primarily due to the following items:

 Oil
 sales decreased $10.0 million, primarily due to lower sales volumes, which decreased oil
 sales by $5.1 million. Oil sales volumes decreased 11% primarily due to the inclusion of
 only eleven months of oil sales volumes in the year ended December 31, 2023. The remaining
 $4.9 million decrease in oil sales was due to lower realized sales prices. The average oil
 price received decreased 12% as a result of the corresponding decrease in the average NYMEX
 oil price for the relevant production months.

 gas sales decreased $6.9 million due to lower realized sales prices, which decreased natural
 gas sales by $3.9 million. The average natural gas price received decreased 27% as a result
 of the corresponding decreases in the average NYMEX gas price for the relevant production
 months. The remaining $3.0 million decrease in natural gas sales was due to lower sales volumes.
 Natural gas sales volumes decreased 17% primarily due to the inclusion of only eleven months
 of natural gas sales volumes in the year ended December 31, 2023.

 Lease
 operating expenses during the year ended December 31, 2023 were $22.1 million compared
 to $21.9 million for the year ended December 31, 2022. Approximately $1.4 million of
 the 2023 expenses were attributable to a settlement between COERT and one of the operators
 of the Underlying Properties relating to a dispute with respect to certain lease operating
 expenses from 2018 and 2019 that the operator had mistakenly coded for Enduro instead of
 the Sponsor. In May 2023, the Sponsor and the operator agreed to settle the dispute
 at a discounted amount, resulting in an incremental lease operating expense adjustment of
 approximately $0.4 million per month from June 2023 through December 2023, after
 which no additional amounts relating to the disputed expenses will be owed to the operator.

 Compression,
 gathering and transportation expenses decreased from $3.3 million in 2022 to $1.7 million
 in 2023 due to lower sales volumes and the inclusion of only eleven months of expenses in
 the year ended December 31, 2023.

 Production,
 ad valorem and other taxes decreased $1.8 million in 2023 compared to 2022, primarily due
 to the decrease in realized sales prices, and lower sales volumes.

 Development
 expenses decreased $5.4 million due to drilling and completion costs for drilling multiple
 new wells in the Permian and Haynesville areas during 2022.

 During the year ended December 31, 2022,
the Sponsor withheld from the net profits otherwise payable to the Trust a net aggregate of $1.0 million for the establishment of a cash
reserve for approved, future development expenses. This reserve was intended to fund an expected increase in development expenses; however,
if those expenses are ultimately delayed or are less than expected, or if the outlook changes, amounts reserved but unspent would be
released as an incremental cash distribution in a future period. This cash reserve for future development was fully released to the Trust
during the year ended 2023.

 The Trust withheld $1.3 million and paid $0.9
million for general and administrative expenses during the year ended December 31, 2023. Expenses paid during the period primarily
consisted of fees for the preparation of 2022 tax information for Trust unitholders, preparation of the Trust's 2022 reserve report
and Annual Report on Form 10-K, 2022 financial statement audit fees, preparation of the Trust's 2023 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,
2022, the Trust withheld $1.7 million and paid $0.8 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. In November 2021, the Trustee notified the
Sponsor of the Trustee's intent to build a cash reserve for the payment of future known, anticipated or contingent expenses or
liabilities of the Trust. From February 2022 through March 2023, the Trustee withheld $37,833, and commencing with the distribution
to Trust unitholders paid in April 2023 has been withholding and, in the future, intends to withhold $50,000, from the funds otherwise
available for distribution each month to gradually build a cash reserve of approximately $2.3 million. The Trustee may increase
or decrease the targeted cash reserve amount at any time and may increase or decrease the rate at which it is withholding funds to build
the cash reserve at any time, without advance notice to the Trust unitholders. Cash held in reserve will be invested as required by the
Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or
contingent expenses or liabilities eventually will be distributed to Trust unitholders, together with interest earned on the funds. As
of December 31, 2023, this cash reserve totaled $941,386.

 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, 2023 and 2022, the Trust held cash reserves of $1,394,697 and $922,913, 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,
the Sponsor 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.

 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:

 interest-bearing
 obligations of the United States government;

 money
 market funds that invest only in United States government securities;

 repurchase
 agreements secured by interest-bearing obligations of the United States government; or

 bank
 certificates of deposit.

 The
Sponsor has not 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, 2023 or 2022, and the terms of the Conveyance prohibit
the Sponsor 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.

 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.

 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 distributable income 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; Any impairment; 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,
2023 or 2022. 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
3. Net Profits Interest in Oil and Gas Properties" of the Notes to Financial Statements in Part II, Item 8 of this
Form 10-K.

 Item 7A.
 Quantitative and Qualitative
 Disclosures About Market Risk.

 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.

 Item 8.
 Financial Statements and Supplementary
 Data.

 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, 2023 and 2022, and the related statements of distributable
income and changes in trust corpus for the years then ended, 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 as of December 31, 2023 and 2022, and its distributable income and changes in trust corpus for the years then ended, in conformity
with the modified cash basis of accounting, as described in Note 2, which is a comprehensive basis of accounting other than accounting
principles generally accepted in the United States of America.

 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 these financial statements based on our audits. We are a public accounting firm registered
with the Public Company Accounting Oversight Board (United States) ("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. The Trust is not required to have, nor were we engaged to perform, an audit
of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control
over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control
over financial reporting. Accordingly, we express no such opinion.

 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 management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

 Critical Audit Matters

 Critical audit matters are matters arising from the current period
audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate
to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective,
or complex judgments. We determined that there are no critical audit matters.

 /s/ Weaver and Tidwell, L.L.P.

 We have served as the Trust's auditor since
2021.

 Houston, Texas

 March 22, 2024

 Statements of Assets,
Liabilities and Trust Corpus

 2023

 2022

 ASSETS

 Cash and cash equivalents

 $
 1,394,697

 $
 922,913

 Net profits interest in oil and natural
 gas properties, net

 50,233,433

 59,641,632

 Total assets

 $
 51,628,130

 $

 LIABILITIES AND TRUST CORPUS

 Trust corpus (33,000,000 units issued
 and outstanding)

 51,628,130

 Total liabilities
 and Trust corpus

 $
 51,628,130

 $

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

 Statements of Distributable
Income

 2023

 2022

 Income
 from net profits interest

 $
 10,347,619

 $
 15,027,041

 Income from sale/lease
 of assets

 245,000

 130,030

 Income from sale
 of producing properties

 4,848,281

 -

 Interest and investment
 income

 63,142

 8,044

 General and administrative
 expenses

 (919,148
)

 (828,818
)

 Cash
 reserves used (withheld) for Trust expenses

 (471,784
)

 (855,797
)

 Distributable
 income

 $
 14,113,110

 $
 13,480,500

 Distributable
 income per unit (33,000,000 units)

 $
 0.427670

 $
 0.408500

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

 Statements of Changes
in Trust Corpus

 2023

 2022

 Trust corpus, beginning
 of period

 $

 $
 65,192,767

 Sale of net profits
 interest of producing properties

 (4,163,851
)

 -

 Cash reserves (used)
 withheld for Trust expenses

 471,784

 855,797

 Distributable income

 14,113,110

 13,480,500

 Distributions to
 unitholders

 (14,113,110
)

 (13,480,500
)

 Amortization
 of net profits interest

 (5,244,348
)

 (5,484,019
)

 Trust corpus,
 end of period

 $
 51,628,130

 $

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

 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 (as amended
and restated, and as further amended, 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.

 On
August 31, 2018, COERT Holdings 1 LLC ("COERT" or the "Sponsor") acquired the Underlying Properties and
all of the outstanding Trust Units owned by Enduro (the "Sale Transaction"). In connection with the Sale Transaction,
the Sponsor 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, 2023, the Sponsor owned 7,363,961 Trust Units, or 22% 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:

 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 of Net Profits Interest, dated effective as of July 1,
 2011 (as supplemented and amended to date, 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 may dispose of all or any material part of the assets of the Trust (including the sale
 of the Net Profits Interests) if approved by at least 75% of the outstanding Trust Units;

 the
 Sponsor may sell a divided or undivided portion of its interests in the Underlying Properties,
 free from and unburdened by the Net Profits Interest, if approved by at least 50% of the
 outstanding Trust Units at a meeting of Trust unitholders;

 the
 Trustee will make monthly cash distributions to Trust unitholders (Note 5);

 the
 Trustee may create a cash reserve to pay for future liabilities of the Trust;

 the
 Trustee 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; in that event, no further
 distributions will be made to Trust unitholders until such amounts borrowed are repaid; and

 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:

 the
 Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells
 the Net Profits Interest;

 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
 holders of at least 75% of the outstanding Trust Units vote in favor of dissolution; or

 the
 Trust is judicially dissolved.

 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:

 (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;
 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 and any impairment recorded 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, 2023 or 2022, 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.

 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. 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, 2023 and 2022 was $302,693,874 and $297,449,525,
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, 2023 or 2022, 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.

 Sale of 2023 Divestiture Properties

 On May 3, 2023, the Sponsor notified the
Trustee that the Sponsor had entered into an agreement to divest certain acreage and associated production in the Permian Basin (the
 "2023 Divestiture Properties") that constituted part of the Underlying Properties and were therefore burdened by the Trust's
Net Profits Interest, for a total purchase price of approximately $6.7 million. On July 19, 2023, at a special meeting of Trust
unitholders, the unitholders approved the foregoing transaction and the release of the Trust's Net Profits Interest in the 2023
Divestiture Properties. On August 9, 2023, the Sponsor completed the sale of the 2023 Divestiture Properties, and the Trustee, on
behalf of the Trust, reconveyed, terminated and released to the Sponsor the Net Profits Interest with respect to the 2023 Divestiture
Properties. The total proceeds received by the Sponsor from the 2023 Divestiture Properties, after preliminary closing adjustments, were
approximately $6.5 million, inclusive of the escrow funded by the buyer and partial expense reimbursement associated with the proxy
solicitation. The Sponsor deducted the final transaction expenses from the sales proceeds, along with an escrow amount of $250,000 to
cover possible indemnification obligations under the purchase and sale agreement (the "Indemnification Escrow Amount"), to
arrive at final net proceeds, based upon the Trust's Net Profits Interest.

 On
September 20, 2023, the Trust announced a special cash distribution to Trust unitholders of $0.069670 per Trust Unit, payable on
October 13, 2023 to Trust unitholders of record on October 2, 2023, reflecting 50% of the Trust's share of the net proceeds,
after accounting for the Indemnification Escrow Amount. The following table displays the aggregate net proceeds from the sale
of the 2023 Divestiture Properties and the aggregate net proceeds allocable to Trust unitholders for this distribution:

 Net Proceeds from sale of 2023 Divestiture

 $
 6,712,000

 Less: Transaction expenses

 (627,149
)

 Plus: Buyer proxy expense reimbursement

 288,000

 Net proceeds from sale of 2023 Divestiture Properties

 $
 6,372,851

 Less: Amount allocable to the Sponsor's
 20% interest

 (1,274,570
)

 Net proceeds allocable to the Trust's 80% Interest

 $
 5,098,281

 Less: Indemnification Escrow amount

 (250,000
)

 Less: Estimated Settlement Escrow
 amount

 (2,549,140
)

 Initial Cash available for distribution by the Trust

 $
 2,299,141

 Number of units

 33,000,000

 Initial special cash distribution per unit

 $
 0.069670

 The remaining 50% of the Trust's share of
the net proceeds was temporarily retained by the Sponsor as a source of payment of the Trust's proportionate share of any post-closing
purchase price adjustments, with any amount remaining (less any amounts in dispute) after such adjustments to be paid to the Trust within
five business days after finalization of the settlement statement and included in a distribution to Trust unitholders.

 On
November 6, 2023, the Trust announced a special cash distribution to Trust unitholders of $0.077250 per Trust Unit, payable on November 22,
2023 to Trust unitholders of record on November 16, 2023, reflecting the remaining 50% of the Trust's share of the net proceeds
(net of the Indemnification Escrow Amount). The following table displays the aggregate net proceeds from the sales of the 2023
Divestiture Properties and the aggregate net proceeds allocable to Trust unitholders for this distribution:

 Net Proceeds from sale of 2023 Divestiture

 $
 6,712,000

 Less: Transaction expenses

 (627,149
)

 Plus: Buyer proxy expense reimbursement

 288,000

 Net proceeds from sale of 2023 Divestiture Properties

 $
 6,372,851

 Less: Amount allocable to the Sponsor's
 20% interest

 (1,274,570
)

 Net proceeds allocable to the Trust's 80% Interest

 $
 5,098,281

 Less: Indemnification Escrow amount

 (250,000
)

 Less: October 13, 2023 Initial
 Cash Distribution

 (2,299,110
)

 Remaining cash available for distribution by the Trust

 $
 2,549,171

 Number of units

 33,000,000

 Remaining special cash distribution per unit

 $
 0.077250

 Within 12 months after the closing of the
sale, any remaining amount from the Indemnification Escrow Amount (less any amounts in dispute) will be released to the Trust and included
in a distribution to Trust unitholders.

 Impairment of Net Profits Interest

 Fair value accounting guidance includes a hierarchy
that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted
quoted prices in active markets for identical assets or liabilities (Level 1 inputs) and the lowest priority to unobservable inputs (Level
3). When indicators of impairment are present and it is determined that the carrying value of the Net Profits Interest exceeds the estimated
undiscounted cash flows of the subject interest, fair value estimates utilized in the impairment assessment are determined based on inputs
not observable in the market and thus represent Level 3 measurements.

 4. 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.

 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. Trust 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. Trust 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.

 5. 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:

 Declaration Date

 Record Date

 Payment Date

 Distribution per Unit

 2023:

 December 16, 2022

 December 30, 2022

 January 14, 2023

 $
 0.058000

 January 18, 2023

 January 31, 2023

 February 14, 2023

 $
 0.056000

 February 17, 2023

 February 28, 2023

 March 13, 2023

 $
 0.019200

 March 16, 2023

 March 31, 2023

 April 14, 2023

 $
 0.019350

 April 17, 2023

 April 28, 2023

 May 12, 2023

 $
 0.030000

 May 15, 2023

 May 31, 2023

 June 14, 2023

 $
 0.013500

 June 16, 2023

 June 30, 2023

 July 14, 2023

 $
 0.012500

 July 17, 2023

 July 31, 2023

 August 14, 2023

 $
 0.053500

 August 18, 2023

 August 31, 2023

 September 15, 2023

 $
 0.009000

 September 18, 2023

 September 29, 2023

 October 13, 2023

 $
 0.003700

 September 20, 2023 – Special Distribution

 October 02, 2023

 October 13, 2023

 $
 0.069670

 October 16, 2023

 October 31, 2023

 November 13, 2023

 $
 0.006000

 November 06, 2023 – Special Distribution

 November 16, 2023

 November 22, 2023

 $
 0.077250

 Total—2023

 $
 0.427670

 2022:

 December 17,
 2021

 2021

 January 14,
 2022

 $
 0.025000

 January 18,
 2022

 January 31,
 2022

 February 14,
 2022

 $
 0.023000

 February 18,
 2022

 February 28,
 2022

 March 14,
 2022

 $
 0.041000

 March 18,
 2022

 March 31,
 2022

 April 14,
 2022

 $
 0.016000

 April 18,
 2022

 April 29,
 2022

 May 13,
 2022

 $
 0.031500

 May 16,
 2022

 May 31,
 2022

 June 14,
 2022

 $
 0.032000

 June 17,
 2022

 June 30,
 2022

 July 15,
 2022

 $
 0.045000

 July 18,
 2022

 July 29,
 2022

 August 12,
 2022

 $
 0.021500

 August 18,
 2022

 August 31,
 2022

 September 15,
 2022

 $
 0.024500

 September 16,
 2022

 September 30,
 2022

 October 17,
 2022

 $
 0.050500

 October 17,
 2022

 October 31,
 2022

 November 14,
 2022

 $
 0.051000

 November 18,
 2022

 November 30,
 2022

 December 13,
 2022

 $
 0.047500

 Total—2022

 $
 0.408500

 6. TRUSTEE
FEES AND RELATED PARTY TRANSACTIONS

 Trustee
Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the
Trustee and $2,010 to the Delaware Trustee. During the years ended December 31, 2023 and 2022, the Trust paid $200,000 to the Trustee
and $2,000 to the Delaware Trustee, respectively, pursuant to the terms of the Trust Agreement.

 Letter
of Credit. Under the terms of the Trust Agreement, COERT has provided the Trust with a $1,200,000 million letter of credit
to be used by the Trust if its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative
expenses. The letter of credit is issued to the benefit of the Trustee. The standby letter of credit was issued by West Texas National
Bank and matures on December 31, 2024. The letter of credit to the Trustee is unfunded as of December 31, 2023.

 Advances
from COERT. 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.

 Registration
Rights Agreement. The Trust and COERT (as the assignee of Enduro, in connection with the Sale Transaction) are parties to
a Registration Rights Agreement, as amended, whereby COERT, its affiliates and certain permitted transferees holding registrable Trust
Units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust
Units, to demand that the Trust effect the registration of the registrable Trust Units. The holders of the registrable Trust Units are
entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement,
COERT will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which
will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units.

 On June 22, 2022, pursuant to the Registration
Rights Agreement, the Trust filed a registration statement on Form S-3 registering the offering by COERT of 8,600,000 Trust Units.
The registration statement was declared effective on July 7, 2022.

 UNAUDITED SUPPLEMENTARY
INFORMATION

 8. Supplementary Oil and Natural Gas Information (Unaudited)

 Oil and Natural Gas Reserve Quantities

 Estimates of proved reserves attributable to the
Trust and the related valuations were based 100% on reports prepared by the Trust's independent petroleum engineers, Cawley, Gillespie &
Associates, Inc. Estimates 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
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:

 2023

 2022

 Oil (per Bbl)

 $
 78.22

 $
 93.67

 Natural gas (per MMBTU)

 $
 2.64

 $
 6.36

 Proved reserve quantity estimates are subject
to numerous uncertainties inherent in the estimation of proved reserves and in the projection of future rates of production and the timing
of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological
interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revisions of
previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs.
The process of estimating quantities of oil and natural gas reserves is very complex, requiring significant subjective decisions in the
evaluation of all available geological, engineering and economic data for each reserve. Consequently, these estimates are expected to
change as additional information becomes available in the future.

 As of December 31, 2023 and 2022, all of
the Underlying Properties' oil and natural gas reserves were attributable to properties within the United States. Proved reserves
attributable to the Trust and related standardized measure valuations are prepared on an accrual basis, which is the basis on which Enduro
and, following the Sale Transaction, the Sponsor, and the Underlying Properties maintain their production records and is different from
the basis on which the Trust production records are computed. The following is a summary of the changes in quantities of proved oil and
natural gas reserves attributable to the Trust for the periods indicated:

 Trust
 Net Profits Interest

 Oil
 (1)
 (MBbls)

 Gas
 (MMcf)

 Total
 (MBOE)

 Balance—January 1, 2022

 3,072

 11,022

 4,909

 Extensions and discoveries

 1,028

 Revisions of previous estimates

 1,121

 (200
)

 1,088

 Income from Net Profits Interest

 (496
)

 (3,357
)

 (1,056
)

 Balance—December 31, 2022

 3,976

 8,493

 5,392

 Extensions and discoveries

 6,584

 1,483

 Revisions of previous estimates

 (1,234
)

 (2,815
)

 (1,703
)

 Divestiture of Reserves

 (525
)

 (126
)

 (546
)

 Income from Net Profits Interest

 (440
)

 (2,782
)

 (904
)

 Balance—December 31, 2023

 2,163

 9,354

 3,722

 Proved developed reserves:

 December 31, 2022

 3,435

 6,901

 4,585

 December 31, 2023

 1,880

 7,706

 3,164

 Proved undeveloped reserves:

 December 31, 2022

 1,591

 December 31, 2023

 1,648

 (1) Reserves
for natural gas liquids are immaterial and included as a component of oil reserves.

 UNAUDITED SUPPLEMENTARY INFORMATION—Continued

 Revisions
of previous estimates. During the year ended December 31, 2023, revisions of previous estimates decreased oil reserves
by 31%, primarily due to a decrease in the average oil price used to estimate future net reserves. The NYMEX average oil price of $78.22
per Bbl used to determine reserves as of December 31, 2023 was 16% lower than the $93.67 per Bbl average NYMEX oil price as of December 31,
2022.

 During the year ended December 31, 2022,
revisions of previous estimates increased oil reserves by 36%, primarily due to an increase in the average oil price used to estimate
future net reserves. The NYMEX average oil price of $93.67 per Bbl used to determine reserves as of December 31, 2022 was 41% higher
than the $66.56 per Bbl average NYMEX oil price as of December 31, 2021.

 Standardized Measure of Discounted Future Net Cash Flows

 The standardized measure of discounted future
net cash flows relating to proved oil and natural gas reserves is computed by applying commodity prices used in determining proved reserves
(with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved
reserves less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves,
discounted using a rate of 10% per year to reflect the estimated timing of the future cash flows. Future cash inflows were computed
by applying the commodity prices utilized in determining proved reserves to estimated future production. Future production and development
costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves at year-end,
based on year-end costs and assuming continuation of existing economic conditions. As the Trust is not subject to federal income taxes,
future income taxes have been excluded.

 The standardized measure of discounted future
net cash flows relating to proved oil and natural gas reserves attributable to the Trust was as follows as of the dates indicated:

 2023

 2022

 (in thousands)

 Future
 cash inflows

 $
 165,087

 $
 383,240

 Future
 production taxes

 (13,316
)

 (31,913
)

 Future net cash
 flows

 $
 151,771

 $
 351,327

 10%
 annual discount for estimated timing of cash flows

 (75,115
)

 (188,167
)

 Standardized
 measure of discounted future net cash flows

 $
 76,656

 $
 163,160

 The changes in standardized measure of discounted
future net cash flows relating to proved oil and natural gas reserves attributable to the Trust for the periods indicated were as follows
(in thousands):

 Year
 Ended December 31,

 2023

 2022

 Extensions, discoveries, and other
 additions

 $

 12,709

 $

 11,570

 Accretion of discount

 16,316

 9,160

 Revisions of previous estimates and other

 (97,416

)

 65,858

 Divestiture of reserves

 (7,765

)

 -

 Income from Net Profits Interest

 (10,348

)

 (15,027

)

 Change in present value
 of future net revenues

 (86,504

)

 71,561

 Balance, beginning of period

 163,160

 91,599

 Balance, end of year

 $

 76,656

 $

 163,160

 Item 9.
 Changes in and Disagreements with Accountants on Accounting
 and Financial Disclosure.

 Not applicable.

 Item 9A.
 Controls and Procedures.

 Evaluation
of Disclosure Controls and Procedures. The Trustee conducted an evaluation of the Trust's disclosure controls and procedures
(as defined in Rules 13a-15 and 15d-15 under the Exchange Act). Based on this evaluation, the Trustee has concluded that the disclosure
controls and procedures of the Trust were effective, as of the end of the period covered by this report, in ensuring that information
required to be disclosed by the Trust in the reports that it files or submits under the Exchange Act is accumulated and communicated
to the Trustee to allow timely decisions regarding required disclosure.

 Due to the nature of the Trust as a passive entity
and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust
Agreement and (ii) the Conveyance, the Trustee's disclosure controls and procedures related to the Trust necessarily rely
on (A) information provided by COERT, including information relating to results of operations, the costs and revenues attributable
to the Trust's interest under the Conveyance and other operating and historical data, plans for future operating and capital expenditures,
reserve information, information relating to projected production, and other information relating to the status and results of operations
of the Underlying Properties and the Net Profits Interest, and (B) conclusions and reports regarding reserves by the Trust's
independent reserve engineers.

 Changes
in Internal Control over Financial Reporting. During the quarter ended December 31, 2023, there were no changes in the
Trust's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect,
the Trust's internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority
over, and makes no statement concerning, the internal control over financial reporting of COERT.

 TRUSTEE'S REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

 The Trustee is responsible for establishing and
maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under
the Exchange Act. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of
financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation
of the effectiveness of the Trust's internal control over financial reporting based on the criteria established in Internal
Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on
the Trustee's evaluation under the framework in Internal Control—Integrated Framework (2013), the Trustee concluded
that the Trust's internal control over financial reporting was effective as of December 31, 2023.

 Item 9B.
 Other Information.

 Rule 10b5-1
Trading Plans. During the three months ended December 31, 2023, no officer or employee of the Trustee who performs policy-making
functions for the Trust adopted, modified, or terminated any Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading
arrangement, as such terms are defined in Item 408(a) of Regulation S-K.

 Item 9C.
 Disclosure Regarding Foreign Jurisdictions
 that Prevent Inspections.

 Not applicable.

 Item 10.
 Directors, Executive Officers
 and Corporate Governance.

 The Trust has no directors or executive officers.
The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding
Trust Units at a meeting at which a quorum is present.

 Audit Committee and Nominating Committee

 Because the Trust does not have a board of directors,
it does not have an audit committee, an audit committee financial expert or a nominating committee.

 Code of Ethics

 The Trust does not have a principal executive
officer, principal financial officer, principal accounting officer or controller and has not adopted a code of ethics applicable to such
persons.

 Item 11.
 Executive Compensation.

 Pursuant to the Trust Agreement, the Trust pays
an annual administrative fee of $200,000 to the Trustee. During the years ended December 31, 2023 and 2022, the Trustee received
$200,000, respectively, in administrative fees and reimbursable expenses from the Trust. The Trust does not have any executive officers,
directors or employees. The Trust does not have a board of directors, and it does not have a compensation committee.

 Item 12.
 Security Ownership of Certain
 Beneficial Owners and Management and Related Unitholder Matters.

 (a) Security
Ownership of Certain Beneficial Owners.

 Based on filings with the SEC, the Trustee is
not aware of any holders of 5% or more of the Trust Units as of March 22, 2024 except as set forth below. The following information
has been obtained from public filings with the SEC.

 Beneficial Owner

 Trust
 Units
 Beneficially
 Owned

 Percent of
 Class

 Permianville Holdings LLC

 7,363,961
 (1)

 22.3
 %

 Jerry Roger Kent

 1,722,300
 (2)

 5.2
 %

 (1)
 Based on a Form 4 dated August 17, 2023 filed by Permianville
 Holdings LLC ("Holdings"). The principal business office address for Holdings
 is 60 Arch Street, 3 rd Floor, Greenwich, CT 06830.

 (2)
 Based on a Schedule 13G/A filed with the SEC on June 23, 2023 by
 Jerry Roger Kent. The principal business office address for the reporting person is 4695
 Preston Park Blvd., Suite 170 East, Plano, Texas 75093-5180. According to the filing,
 the reporting person has sole voting power with respect to 1,507,300 Trust Units, shared
 voting power with respect to 215,000 Trust Units, sole dispositive power with respect to
 1,507,300 Trust Units, and shared dispositive power with respect to 215,000 Trust Units.

 (b) Security Ownership of Management.

 Not applicable.

 (c) Changes in Control.

 The registrant knows of no arrangement, including
any pledge by any person of securities of the registrant or any of its parents, the operation of which may at a subsequent date result
in a change of control of the registrant. See "Certain Relationships and Related Transactions, and Director Independence—Registration
Rights Agreement" in Part III, Item 13 of this Form 10-K.

 Item 13.
 Certain Relationships and
 Related Transactions, and Director Independence.

 Trustee
Administrative Fee. Under the terms of the Trust Agreement, the Trust pays an annual administrative fee of $200,000 to the
Trustee and $2,000 to the Delaware Trustee.

 Registration
Rights Agreement. The Trust and COERT (as the assignee of Enduro in connection with the Sale Transaction) are parties to a
Registration Rights Agreement, as amended, whereby COERT, its affiliates and certain permitted transferees holding registrable Trust
Units are entitled, upon receipt by the Trustee of written notice from holders of a majority of the then outstanding registrable Trust
Units, to demand that the Trust effect the registration of the registrable Trust Units. The holders of the registrable Trust Units are
entitled to demand a maximum of five such registrations. In connection with the preparation and filing of any registration statement,
COERT will bear all costs and expenses incidental to any registration statement, excluding certain internal expenses of the Trust, which
will be borne by the Trust. Any underwriting discounts and commissions will be borne by the seller of the Trust Units. The foregoing
description of the Registration Rights Agreement is qualified in its entirety by the terms of the Registration Rights Agreement, and
Amendment No. 1 thereto, copies of which are incorporated by reference as exhibits to this Form 10-K.

 On June 22, 2022, pursuant to the Registration
Rights Agreement, the Trust filed a registration statement on Form S-3 registering the offering by COERT of 8,600,000 Trust Units. The
registration statement was declared effective on July 7, 2022.

 Director Independence

 The Trust does not have a board of directors.

 Item 14.
 Principal Accountant Fees
 and Services.

 The
Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other
professional service firms and related fees are granted by the Trustee. The Trustee has appointed Weaver and Tidwell, LLP as the
independent registered public accounting firm to audit the Trust's financial statements for the fiscal year ending December 31,
2024. During the years ended December 31, 2023 and 2022, Weaver and Tidwell, LLP served as the Trust's independent registered
public accounting firm.

 The following table presents the aggregate fees
paid by the Trust for the years ended December 31, 2023 and 2022 by Weaver and Tidwell, LLP:

 2023

 2022

 Audit
 fees (1)

 $
 71,535

 $
 98,365

 Audit-related fees

 —

 —

 Tax fees

 —

 —

 All other fees

 —

 —

 Total fees

 $
 71,535

 $
 98,365

 (1)
 Fees billed for professional services rendered for the audit of the Trust's
 financial statements and reviews of the financial statements included in the Trust's
 quarterly reports and annual financial statements.

 Item 15.
 Exhibit and Financial
 Statement Schedules.

 (a)(1) Financial Statements

 The following financial statements are set forth
under "Financial Statements and Supplementary Data" in Part II, Item 8 of this Form 10-K on the pages indicated:

 Page in this

 Form 10-K

 Report
 of Independent Registered Public Accounting Firm (PCAOB Identification No. 410)

 Statements
 of Assets, Liabilities and Trust Corpus

 Statements
 of Distributable Income

 Statements
 of Changes in Trust Corpus

 Notes
 to Financial Statements

 Unaudited
 Supplementary Information

 (a)(2) Schedules

 Schedules have been omitted because they are not
required, not applicable or the information required has been included elsewhere herein.

 (a)(3) Exhibits

 See Index to Exhibits.

 Item 16.
 Form 10-K Summary.

 None.

 INDEX TO EXHIBITS

 Exhibit

 Number

 Description

 2.1*

 Agreement
 and Plan of Merger of Enduro Royalty Trust and Enduro Texas LLC, dated as of November 3, 2011 by and between the Bank of New
 York Mellon Trust Company, N.A., as Trustee of Enduro Royalty Trust, and Enduro Texas LLC. (Incorporated herein by reference to Exhibit 1.2
 to the Trust's Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))

 3.1*

 Certificate
 of Trust of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 3.3 to the Registration Statement on Form S-1,
 filed on May 16, 2011 (Registration No. 333-174225))

 3.2*

 Certificate
 of Amendment to Certificate of Trust. (Incorporated herein by reference to Exhibit 3.1 to the Trust's Current Report on
 Form 8-K filed on September 5, 2018 (File No. 1-35333))

 3.3*

 Amended
 and Restated Trust Agreement of Enduro Royalty Trust, dated as of November 3, 2011, among Enduro Resource Partners LLC, The
 Bank of New York Mellon Trust Company, N.A., as Trustee of Enduro Royalty Trust, and Wilmington Trust Company, as Delaware Trustee
 of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 3.1 to the Trust's Current Report on Form 8-K
 filed on November 8, 2011 (File No. 1-35333))

 3.4*

 First
 Amendment to Amended and Restated Trust Agreement, dated September 6, 2017 but effective as of August 30, 2017, among Enduro
 Resource Partners LLC, Wilmington Trust Company, as Delaware Trustee, and The Bank of New York Mellon Trust Company, N.A., as Trustee.
 (Incorporated herein by reference to Exhibit 3.1 to the Trust's Current Report on Form 8-K filed on September 12,
 2017 (File No. 1-35333))

 3.5*

 Second
 Amendment to Amended and Restated Trust Agreement of Enduro Royalty Trust, dated September 14, 2018, among COERT Holdings 1
 LLC, Wilmington Trust Company, as Delaware trustee, and The Bank of New York Mellon Trust Company, N.A., as trustee. (Incorporated
 herein by reference to Exhibit 3.1 to the Trust's Current Report on Form 8-K filed on September 14, 2018
 (File No. 1-35333))

 4.1*

 Registration
 Rights Agreement, dated as of November 8, 2011, by and between Enduro Resource Partners LLC and Enduro Royalty Trust. (Incorporated
 herein by reference to Exhibit 10.3 to the Trust's Current Report on Form 8-K filed on November 8, 2011 (File
 No. 1-35333))

 4.2*

 Amendment
 No. 1 to Registration Rights Agreement, dated as of November 8, 2012, by and between Enduro Resource Partners LLC and Permianville
 Royalty Trust. (Incorporated herein by reference to Exhibit 4.2 to the Trust's Annual Report on Form 10-K for the
 year ended December 31, 2012 (File no. 1-35333))

 4.3*

 Description
 of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934. (Incorporated herein by reference
 to Exhibit 4.3 to the Trust's Annual Report on Form 10-K for the year ended December 31, 2019 (File no. 1-35333))

 10.1*

 Conveyance
 of Net Profits Interest, dated November 8, 2011, by and between Enduro Operating LLC and Enduro Texas LLC. (Incorporated herein
 by reference to Exhibit 10.1 to the Trust's Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))

 10.2*

 Supplement
 to Conveyance of Net Profits Interest, dated November 8, 2011, from Enduro Operating LLC, Enduro Texas LLC and The Bank of New
 York Mellon Trust Company, N.A. as Trustee of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 10.2 to the
 Trust's Current Report on Form 8-K filed on November 8, 2011 (File No. 1-35333))

 10.3*

 First
 Amendment to Conveyance of Net Profits Interest, dated September 6, 2017, among Enduro Operating LLC and The Bank of New York
 Mellon Trust Company, N.A., as Trustee of Enduro Royalty Trust. (Incorporated herein by reference to Exhibit 10.1 to the Trust's
 Current Report on Form 8-K filed on September 12, 2017 (File No. 1-35333))

 10.4*

 Partial
 Release, Reconveyance and Termination Agreement, dated September 6, 2017, by and between The Bank of New York Mellon Trust Company,
 N.A., as Trustee of Enduro Royalty Trust, and Enduro Operating LLC. (Incorporated herein by reference to Exhibit 10.2 to the
 Trust's Current Report on Form 8-K filed on September 12, 2017 (File No. 1-35333))

 23.1

 Consent
 of Cawley, Gillespie & Associates, Inc.

 23.2

 Consent of Weaver and
 Tidwell, L.L.P.

 31.1

 Certification
 pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 32.1

 Certification
 pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 97.1

 Permianville Royalty
 Trust Clawback Policy

 99.1

 Report
 of Cawley, Gillespie & Associates, Inc.

 * Asterisk indicates exhibit previously filed with the SEC and
incorporated herein by reference.

 SIGNATURES

 Pursuant to the requirements of Section 13
or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned,
thereunto duly authorized.

 Date: March 22, 2024

 By:

 THE BANK OF NEW YORK MELLON TRUST COMPANY,
 N.A., AS TRUSTEE

 By:

 /s/
 SARAH NEWELL

 Name: Sarah Newell

 Title: Vice President

 The Registrant, Permianville Royalty Trust, has
no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly,
no additional signatures are available and none have been provided. In signing the report above, the Trustee does not imply that it has
performed any such function or that such function exists pursuant to the terms of the Trust Agreement under which it serves.