NYSE: PVL

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.

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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.

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

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·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,
2025, this cash reserve totaled $1,441,386.

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;

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·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:

Year Ended December 31,

2025
2024

Pioneer Natural Resources USA
19%
23%

Phillips 66
18%
18%

BPX Operating Company
14%
2%

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.

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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 23, 2026.

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.

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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.

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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;

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·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.

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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 September 2025, the Sponsor sold approximately $0.4 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 December 15, 2025.

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.

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

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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.

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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.”

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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 98th 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.

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How the EPA and the USACE define “waters
of the United States” (“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, has been the subject
of controversy and litigation for decades and can impact the Sponsor’s regulatory and permitting obligations under the CWA. In 2023,
in Sackett v. EPA, the Supreme Court issued a landmark decision interpreting WOTUS more narrowly than the then-current definition
contemplated, resulting in diminished jurisdiction over wetlands and streams that lacked certain connections to other waters or consistent
water flow. Following Sackett, because of ongoing litigation, the regulatory landscape currently remains unsettled. The regulations
currently in effect in 24 states define WOTUS using a 2023 regulation modified after the Sackett decision. In the rest of the country,
the agencies base jurisdiction on an earlier WOTUS definition as implemented in light of a number of Supreme Court decisions, including
Sackett. Despite the two approaches, jurisdiction over WOTUS is essentially consistent across the United States.

In November 2025, the USACE released a proposed
rule revising the regulatory definition of WOTUS. That new definition is expected to go into effect in early 2026 without substantial
changes from the proposed definition. Regardless of the ultimate details, the revised definition likely will further reduce CWA jurisdiction,
especially over wetlands and streams, leading to fewer permitting requirements. Once the new WOTUS definition is final, litigation will
likely continue challenging the legality of the definition. This litigation could have the effect of delaying or precluding implementation
of the new rule. 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 activities related to 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 NWPs expire in March 2026 and will be replaced, simultaneously,
with new versions that are largely unchanged from the previous set. Litigation challenging the NWPs, if filed, could result in additional
cost and time for permitting projects.

In February 2025, the USACE began implementing
emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency. This has
resulted, in many instances, in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects
subject to the Executive Order.

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 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 the EPA’s ability to fully assess the potential impacts
to drinking water resources. To date, the EPA has taken no further action in response to the December 2016 report. However, in April 2024,
the BLM issued a final rule to reduce the waste of natural gas from venting, flaring, and leaks during oil and gas production activities
on federal and American Indian leases.

14

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 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. However, in May 2015, the Texas legislature enacted a bill preempting local bans on hydraulic fracturing. Meanwhile,
in Texas, specific oil and natural gas regulations apply to oil and gas operations, including the drilling, completion and operations
of wells, and the disposal of waste oil and salt water. In October 2023, the Texas Railroad Commission (“RRC”) announced
draft amendments to its water protection rules to, among other things, encourage waste recycling. There are also procedures incident
to the plugging and abandonment of dry holes or other non-operational wells, all as governed by the applicable governing state agency.
As an example, the RRC adopted rules in 2014 requiring companies seeking permits for disposal wells to provide seismic activity data
in permit applications. The rules also allow the RRC to modify, suspend, or terminate permits if a disposal well is determined to
be causing seismic activity. Determinations by the RRC under these rules may adversely affect our operations.

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, the EPA adopted a final rule in
2024 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.

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The results of the 2024 presidential election and
President Trump’s energy agenda prioritizing domestic oil and gas production likely will impact the air quality-related requirements
that apply to the Sponsor. In March 2025, the EPA announced it was reconsidering the 2024 rules that established new volatile
organic compound and methane emissions standards for both new and existing sources. Following that announcement, the EPA adopted amendments
to the NSPS and existing source performance standards that extended the compliance deadlines for many of the new source requirements adopted
in 2024 and extended the state plan submittal deadlines, which will effectively extend the dates by which existing sources must come into
compliance with the existing source emissions guidelines. It is currently unknown whether EPA’s reconsideration of the 2024 rules will
result in further changes. Similar to prior changes to the air pollution control standards for oil and gas sources, the most recent changes
will be subject to judicial review, as well as the potential for future presidential administrations to take a different approach.

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. Likewise, in March 2024, the EPA issued a final rule that lowered the annual standard for fine particulate matter
from 12 to 9 micrograms per cubic meter. In March 2025, however, the EPA announced that it would reconsider the rule lowering
the fine particulate matter standard, and the EPA has filed a request that the U.S. Court of Appeals vacate the 2024 rule. In 2026, the
EPA also has delayed taking certain actions necessary to implement air quality requirements under the lower 2024 standard. No regulatory
action or court decision has changed the 2024 rule lowering the fine particulate matter standard, and the EPA’s delayed implementation
of the 2024 standard likely will be subject to judicial review. 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.

The Sponsor may be required to incur certain capital
expenditures for air pollution control equipment or other air emissions-related issues. The Sponsor currently does not expect that such
requirements will have a material adverse effect on its operations.

Climate change. The Trump Administration’s
efforts to roll back federal regulation of greenhouse gases (“GHGs”) represent a significant shift in federal climate policy,
though the ultimate impact of those efforts on the Sponsor is unclear. In 2009, the EPA found that emissions of carbon dioxide, methane
and GHGs may present an endangerment to public health and the environment and subsequently 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 methane emissions guidelines for existing oil and gas
sources that were adopted in 2024. 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. Shortly
after President Trump took office in January 2025, the federal government embarked on a series of changes relating to climate policy
and regulation. On January 20, 2025, President Trump announced the withdrawal of the United States from the Paris Climate Agreement.
In July 2025, the EPA issued a proposed rule to rescind the 2009 GHG endangerment finding that provided a basis for GHG regulation
under the CAA. In September 2025, the EPA proposed to rescind the GHG reporting program for sectors other than the oil and gas sector,
while proposing to suspend GHG reporting requirements for the oil and gas sector until 2034. In February 2026, the EPA adopted a
final rule repealing its prior endangerment finding, which opens the door for the EPA to repeal its GHG rules for the oil and
gas sector.

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The EPA has established methane standards for oil
and gas sources based on the now-repealed GHG endangerment finding. In 2024, 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 reductions in methane and volatile organic
compound 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 arriving in
2029. In 2025, however, the EPA extended certain compliance deadlines for both new and existing sources, and the 2026 endangerment finding
repeal provides a basis for undoing the oil and gas methane standards – though the fact that the oil and gas standards address both
methane and volatile organic compounds, which are regulated independently of the EPA’s authority to regulate GHGs, may limit the
impact of future changes to the methane standards that currently apply to oil and gas sources.

The Inflation Reduction Act of 2002 (the “IRA”)
included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) 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 adopted new rules to implement
the WEC program in November 2024; however, the fate of the WEC and the EPA rules implementing the WEC is unclear. In March 2025,
President Trump signed legislation repealing the EPA’s 2024 WEC rules under the Congressional Review Act. The repeal of the
EPA’s WEC rules did not eliminate the statutory requirement to pay the WEC, but it eliminated the rules established by
the EPA to determine the WEC due, the payment mechanism, and any payment deadlines. The U.S. Congress may be considering amendment or
repeal of certain portions of the IRA, including the statutory provisions establishing the WEC.

Meanwhile, 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 to date have 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. For example, the states of Colorado and New Mexico have adopted rules regulating
GHGs from the oil and gas industry that are based on the federal standards. Congress may in the future consider adopting other 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. Driven by court decisions and Administration
policy, NEPA implementation and resulting litigation changed dramatically in 2025. Key changes are driving agencies to narrow their NEPA
reviews and complete them faster and are driving courts to show more deference to agencies when reviewing the adequacy of an agency’s
analysis under NEPA, benefitting private projects that may require federal permits and reviews.

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In particular, until 2025, agencies undertook NEPA
reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”) as well as pursuant
to the federal agency’s own NEPA procedures. After two federal courts found that CEQ did not have authority to issue binding regulations,
CEQ withdrew their regulations. In their place, agencies each issued their own NEPA procedures and, for the most part, put those procedures
in agency guidance rather than binding regulations, although the UUSACE (which issues permits that can be critical to construction) regulatory
program is a notable exception, keeping its NEPA procedures in regulations. While the agency procedures were based on a CEQ template,
there are inconsistencies among the agencies on various topics, including the requirement for public comment and consideration of various
types of impacts. These procedures make changes that are intended to streamline reviews.

Also, on May 29, 2025, the Supreme Court decided
Seven County Infrastructure Coalition v. Eagle County, Colorado, in which the Court expressed clear intention that NEPA
should be brought “back in line with the statutory text and common sense.” Significantly for permits that may be needed for
private projects, the Court clarified that agencies need only evaluate the effects of the specific “proposed action” before
them, not the impacts of “other future or geographically separate projects that may be built (or extended) as a result of or in
the wake of the immediate project under consideration.” The Court also emphasized that courts must afford agencies substantial deference
in reviewing agency actions under NEPA and that agencies “must have broad latitude to draw a ‘manageable line’”
when determining the appropriate scope of analysis. The Court’s decision may reduce litigation risk and help streamline federal
reviews.

Endangered Species Act. The federal Endangered
Species Act, as amended (“ESA”), prohibits taking 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 (the “Services”)
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. Changes to implementing rules in the Biden Administration may, in some instances, make a federal review
process occasioned by the application for permits, rights of way, or leases more complex in certain circumstances. 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. However, in 2025, the Services
issued proposed revisions to the regulations implementing the ESA Section 7 consultation process and the scope of the definition
of the term “take.” These regulations, if finalized, generally would be deregulatory in nature, modestly reducing the coverage
of the ESA and streamlining the ESA section 7 consultation process. Nevertheless, these rules are expected to be immediately challenged
in litigation, which will create uncertainty as to if and when these rules will go into effect. In January 2025, the Trump Administration
directed the use of the emergency consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency
Executive Order.

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.

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Where You Can Find Other Information

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