What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2022-03-25 compared with 2021-03-23 · 982 added, 914 removed, 47 unchanged (98% of the section changed)

Royalty Trust (the “Trust”), previously known as Enduro Royalty Trust, is a Delaware statutory trust formed in May

2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”),

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

(the “Trustee”), as trustee, and Wilmington Trust Company

(the “Delaware Trustee”), as Delaware Trustee.

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.”

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.

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.

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.

October 2013, Enduro completed a secondary offering of 11,200,000 Trust Units at a price to the public of $13.85 per unit.

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.

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

This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of

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”).

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.

July 2018, Enduro entered into a purchase and sale agreement with COERT Holdings 1 LLC (“COERT”

or the “Sponsor”)

for the Underlying Properties and all of the outstanding Trust Units owned by Enduro (the “Sale Transaction”), and

on August 31, 2018, the parties closed the Sale Transaction.

In connection with the Sale Transaction, COERT assumed all of Enduro’s

obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were parties.

COERT is a Delaware

limited liability company engaged in the production and development of oil and natural gas from properties located in the Rockies,

the Permian Basin of west Texas and southeastern New Mexico, and the Arklatex region of Texas and Louisiana.

to “COERT”

Permianville Royalty Trust (the “Trust”),

previously known as Enduro Royalty Trust, is a Delaware statutory trust formed in May 2011 pursuant to a trust agreement (the “Trust

Agreement”) among Enduro Resource Partners LLC (“Enduro”), as trustor, The Bank of New York Mellon Trust Company, N.A.

(the “Trustee”), as trustee, and Wilmington Trust Company (the “Delaware Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for

the benefit of the Trust unitholders a net profits interest representing the right to receive 80% of the net profits from the sale of

oil and natural gas production from certain properties in the states of Texas, Louisiana and New Mexico held by Enduro as of the date

of the conveyance of the net profits interest to the Trust (the “Net Profits Interest”).

The properties in which the Trust

holds the Net Profits Interest are referred to as the “Underlying Properties.”

In connection with the closing of the initial

public offering of units of beneficial interest in the Trust (“Trust Units”) in November 2011, Enduro Operating LLC,

a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro Operating”), and Enduro Texas LLC, a Texas

limited liability company and a wholly owned subsidiary of Enduro (“Enduro Texas”), merged, with each entity surviving the

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.

2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which amended

certain provisions of the Trust Agreement to, among other things, allow Enduro to sell interests in the Underlying Properties free and

clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of the Trust

at a meeting held in accordance with the requirements of the Trust Agreement.

This amendment reduced the required threshold for approval

of such sales from 75% to 50% of the outstanding units of the Trust.

To effect the same changes as those included in the amended Trust

Agreement, Enduro, the Trustee and the Delaware Trustee also entered into the First Amendment to Conveyance of Net Profits Interest.

As a result of the Trust unitholders approving amendments to the Trust Agreement and Conveyance and the approval of the divestiture of

certain properties in the Permian Basin, Enduro and the Trustee entered into the Partial Release, Reconveyance and Termination Agreement

(the “Partial Release”).

Pursuant to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated

and released to Enduro the Net Profits Interest with respect to certain of the Underlying Properties sold pursuant to eight letter agreements

or purchase and sale agreements, as applicable, entered into between Enduro and eight separate counterparties.

In July 2018, Enduro entered into a purchase and

sale agreement with COERT Holdings 1 LLC (“COERT”

or the “Sponsor”) for the Underlying Properties and all of

the outstanding Trust Units owned by Enduro (the “Sale Transaction”), and on August 31, 2018, the parties closed the Sale

In connection with the Sale Transaction, COERT assumed all of Enduro’s obligations under the Trust Agreement and other

instruments to which Enduro and the Trustee were parties.

COERT is a Delaware limited liability company engaged in the production and

development of oil and natural gas from properties located in the Rockies, the Permian Basin of west Texas and southeastern New Mexico,

and the Arklatex region of Texas and Louisiana.

References to “COERT”

or the “Sponsor”

in this Form 10-K refer to COERT Holdings 1 LLC, the current sponsor of the

Trust, and references to “Enduro”

in this Form 10-K refer to Enduro Resource Partners LLC, the original sponsor of

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.

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.

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.

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:

cash attributable to the Net Profits Interest;

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

distributable cash to the Trust unitholders;

to be prepared and distributed a tax information report for each Trust unitholder and

preparing and filing tax returns on behalf of the Trust;

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;

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;

the Trust’s rights under certain agreements;

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

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.

supplement or amendment, however, may not materially adversely affect the interests of the Trust unitholders.

Trustee may create a cash reserve to pay for future liabilities of the Trust and may authorize the Trust to borrow money to pay

administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves.

The Trustee may authorize

the Trust to borrow from any person, including the Trustee, the Delaware Trustee or an affiliate thereof, although none of the

Trustee, the Delaware Trustee nor any affiliate thereof intends to lend funds to the Trust.

The Trustee may also cause the Trust

to mortgage its assets to secure payment of the indebtedness.

The terms of such indebtedness and security interest, if funds were

loaned by the Trustee, Delaware Trustee or an affiliate thereof, would be similar to the terms that such entity would grant to

a similarly situated commercial customer with whom it did not have a fiduciary relationship.

Under the terms of the Trust Agreement,

COERT has provided the Trust with a $1.2 million letter of credit to be used by the Trust in the event that its cash on hand (including

available cash reserves) is not sufficient to pay ordinary course administrative expenses.

If the Trust requires more than the

$1.2 million under the letter of credit to pay administrative expenses, COERT has agreed to loan funds to the Trust necessary

to pay such expenses.

If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust

unitholders until such amounts borrowed or drawn are repaid.

The total amount drawn of $348,821 as of December 31, 2020 will be

recouped from the subsequent distribution as a reduction of NPI income received from the Sponsor.

month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds received

from the Net Profits Interest.

The cash held by the Trustee as a reserve against future liabilities or for distribution at the

next distribution date may be held in a noninterest-bearing account or may be invested in:

interest-bearing

obligations of the United States government;

market funds that invest only in United States government securities;

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

certificates of deposit.

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:

Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells

the Net Profits Interest;

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;

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

Trust is judicially dissolved.

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.

and Post-Production Services

to the terms of the Conveyance, the Sponsor has the responsibility to market, or cause to be marketed, the oil and natural gas

production attributable to the Net Profits Interest in the Underlying Properties.

The terms of the Conveyance restrict the Sponsor

from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to

non-affiliates.

Accordingly, a marketing fee is not deducted (other than fees paid to non-affiliates) in the calculation of the

Net Profits Interest’s share of net profits.

The net profits to the Trust from the sales of oil and natural gas production

from the Underlying Properties attributable to the Net Profits Interest is determined based on the same price that the Sponsor

receives for sales of oil and natural gas production attributable to the Sponsor’s interest in the Underlying Properties.

However, if the oil or natural gas is processed, the net profits receive the same processing upgrade or downgrade as the Sponsor.

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

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.

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

The contract prices are based on a published regional index price, after adjustments for Btu content, transportation and

related charges.

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”

in this Form 10-K refer to COERT Holdings 1 LLC, the current sponsor of the Trust, and references to “Enduro”

10-K refer to Enduro Resource Partners LLC, the original sponsor of the Trust.

The Net Profits Interest is passive in nature

and neither the Trust nor the Trustee has any management control over or responsibility for costs relating to the operation of the Underlying

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

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;

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 and may authorize the Trust to borrow money to pay administrative or incidental expenses of the Trust

that exceed its cash on hand and available reserves.

The Trustee may authorize the Trust to borrow from any person, including the Trustee,

the Delaware Trustee or an affiliate thereof, although none of the Trustee, the Delaware Trustee nor any affiliate thereof intends to

lend funds to the Trust.

The Trustee may also cause the Trust to mortgage its assets to secure payment of the indebtedness.

of such indebtedness and security interest, if funds were loaned by the Trustee, Delaware Trustee or an affiliate thereof, would be similar

to the terms that such entity would grant to a similarly situated commercial customer with whom it did not have a fiduciary relationship.

Under the terms of the Trust Agreement, COERT has provided the Trust with a $1.2 million letter of credit to be used by the Trust in

the event that its cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative expenses.

If the Trust requires more than the $1.2 million under the letter of credit to pay administrative expenses, COERT has agreed to loan

funds to the Trust necessary to pay such expenses.

If the Trust borrows funds or draws on the letter of credit, no further distributions

will be made to Trust unitholders until such amounts borrowed or drawn are repaid.

In November 2021, the Trustee notified COERT

that the Trustee intends to build a reserve for the payment of future known, anticipated or contingent expenses or liabilities.

with the distribution to Trust unitholders paid in February 2022, the Trust is withholding, and in the future intends to withhold, $37,833

from the funds otherwise available for distribution each month to gradually build a cash reserve of approximately $2.3 million.

cash is reserved for the payment of future known, anticipated or contingent expenses or liabilities of the Trust.

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.

Each month, the Trustee pays Trust obligations

and expenses and distributes to the Trust unitholders the remaining proceeds received from the Net Profits Interest.

The cash held by

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

account or may be invested in:

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;

bank certificates of

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.

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;

the Trust is judicially

Upon dissolution of the Trust,

the Trustee would sell all of the Trust’s assets, either by private sale or public auction, and, after payment or the making of

reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of the sale to the Trust unitholders.

Marketing and Post-Production Services

Pursuant to the terms of the Conveyance, the Sponsor

has the responsibility to market, or cause to be marketed, the oil and natural gas production attributable to the Net Profits Interest

in the Underlying Properties.

The terms of the Conveyance restrict the Sponsor from charging any fee for marketing production attributable

to the Net Profits Interest other than fees for marketing paid to non-affiliates.

Accordingly, a marketing fee is not deducted (other

than fees paid to non-affiliates) in the calculation of the Net Profits Interest’s share of net profits.

The net profits to the

Trust from the sales of oil and natural gas production from the Underlying Properties attributable to the Net Profits Interest is determined

based on the same price that the Sponsor receives for sales of oil and natural gas production attributable to the Sponsor’s interest

in the Underlying Properties.

However, if the oil or natural gas is processed, the net profits receive the same processing upgrade or

downgrade as the Sponsor.

The operators of the Underlying Properties sell

the oil produced from the Underlying Properties to third-party crude oil purchasers.

Oil production from the Underlying Properties is

typically transported by truck from the field to the closest gathering facility or refinery.

The operators sell the majority of the oil

production from the Underlying Properties under contracts using market sensitive pricing.

The price received by the operators for the

oil production from the Underlying Properties is usually based on a regional price applied to equal daily quantities in the month of

delivery that is then reduced for differentials based upon delivery location and oil quality.

Natural gas produced by the operators is

marketed and sold to third-party purchasers.

The natural gas is sold pursuant to contracts with such third parties, and the sales contracts

are in their secondary terms and are on a month-to-month basis.

The contract prices are based on a published regional index price, after

adjustments for Btu content, transportation and related charges.

The following purchasers individually accounted

for ten percent or more of sales from the Underlying Properties that were included in calculating the Trust’s “Income from

net profits interest”

for the periods presented.

The table provides

the percentage represented by the purchasers during the periods presented:

The table provides the percentage represented by the purchasers during the periods

Year Ended December 31,

2 unchanged sentences

HollyFrontier

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.

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.

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.

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’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.

of Trust Units

Trust Unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro

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, 2021.

Distributions

and Income Computations

month, the Trustee determines the amount of funds available for distribution to the Trust unitholders.

Available funds are the

excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts

reserved by the Trustee) that month, over the Trust’s liabilities for that month.

Available funds are reduced by any cash

the Trustee decides to hold as a reserve against future liabilities.

The holders of Trust Units as of the applicable record date

(generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business

day after the record date.

In the event that the net profits for any computation period is a negative amount, the Trust will receive

no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following

computation period for purposes of determining the net profits for that following computation period.

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.

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.

in the availability or price of oil, natural gas or other forms of energy, as well as business conditions, conservation, legislation,

regulations and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas.

Future prices for oil and natural gas will directly

impact Trust distributions, estimates of reserves attributable to the Trust’s interests and estimated and actual future net revenues

to the Trust.

In view of the many uncertainties that affect the supply and demand for oil and natural gas, neither the Trust nor the Sponsor

can make reliable predictions of future oil and natural gas supply and demand or future product prices.

Nevertheless, lower product prices

generally will result in lower distributions, lower estimates of reserves attributable to the Trust’s interests and lower estimated

and actual future net revenues to the Trust.

All the Trust’s assets

are located in the United States.

The operators of the Underlying Properties sell the oil and natural gas produced from the Underlying

Properties to third-party purchasers in the United States.

Demand for natural gas generally is higher in the winter months, but otherwise

seasonal factors do not affect the Trust.

Description of Trust Units

Each Trust Unit is a unit of beneficial interest

in the Trust and is entitled to receive cash distributions from the Trust on a pro rata basis.

Each Trust unitholder has the same rights

regarding his or her Trust Units as every other Trust unitholder has regarding his or her units.

The Trust Units are in book-entry form

only and are not represented by certificates.

The Trust had 33,000,000 Trust Units outstanding as of March 25, 2022.

Distributions and Income Computations

Each month, the Trustee determines the amount of

funds available for distribution to the Trust unitholders.

Available funds are the excess cash, if any, received by the Trust from the

Net Profits Interest and other sources (such as interest earned on any amounts reserved by the Trustee) that month, over the Trust’s

liabilities for that month.

Available funds are reduced by any cash the Trustee decides to hold as a reserve against future liabilities.

The holders of Trust Units as of the applicable record date (generally the last business day of each calendar month) are entitled to monthly

distributions payable on or before the 10th business day after the record date.

In the event that the net profits for any computation

period is a negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will

be deducted from gross profits in the following computation period for purposes of determining the net profits for that following computation

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.

the Trustee could establish a reserve in one month that would not result in a tax deduction until a later month.

of Trust Units

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

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

Delaware law and the Trust Agreement govern all matters affecting the title, ownership or transfer of Trust Units.

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.

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.

of Trust Unitholders

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.

Rights of Trust Unitholders

Trustee or Trust unitholders owning at least 10% of the outstanding Trust Units may call meetings of Trust unitholders.

is responsible for all costs associated with calling a meeting of Trust unitholders, unless such meeting is called by the Trust

unitholders in which case the Trust unitholders are responsible for all costs associated with calling such meeting.

Meetings must

be held in such location as is designated by the Trustee in the notice of such meeting.

The Trustee must send notice of the time

and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60

days before the meeting.

Trust unitholders representing a majority of Trust Units outstanding must be present or represented to

have a quorum.

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.

may treat the owner of any Trust Unit as shown by its records as the owner of the Trust Unit.

The Trustee will not be considered to know

about any claim or demand on a Trust Unit by any party except the record owner.

A person who acquires a Trust Unit after any monthly record

date will not be entitled to the distribution relating to that monthly record date.

Delaware law and the Trust Agreement govern all matters

affecting the title, ownership or transfer of Trust Units.

Periodic Reports

The Trustee files all required Trust federal and

state income tax and information returns.

The Trustee prepares and mails to Trust unitholders annual reports that Trust unitholders need

to correctly report their share of the income and deductions of the Trust.

The Trustee also causes to be prepared and filed reports that

are required to be filed under the Exchange Act and by the rules of any securities exchange or quotation system on which the Trust Units

are listed or admitted to trading, and also causes the Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including

but not limited to, establishing, evaluating and maintaining a system of internal control over financial reporting in compliance with

the requirements of Section 404 thereof.

Each Trust unitholder and his or her representatives

may examine, for any proper purpose, during reasonable business hours, the records of the Trust and the Trustee, subject to such restrictions

as are set forth in the Trust Agreement.

Liability of Trust Unitholders

Under the Delaware Statutory Trust Act, Trust unitholders

are entitled to the same limitation of personal liability extended to stockholders of private corporations for profit under the General

Corporation Law of the State of Delaware.

The courts in jurisdictions outside of Delaware, however, might not give effect to such limitation.

Voting Rights of Trust Unitholders

The Trustee or Trust unitholders owning at least

10% of the outstanding Trust Units may call meetings of Trust unitholders.

The Trust is responsible for all costs associated with calling

a meeting of Trust unitholders, unless such meeting is called by the Trust unitholders in which case the Trust unitholders are responsible

for all costs associated with calling such meeting.

Meetings must be held in such location as is designated by the Trustee in the notice

of such meeting.

The Trustee must send notice of the time and place of the meeting and the matters to be acted upon to all of the Trust

unitholders at least 20 days and not more than 60 days before the meeting.

Trust unitholders representing a majority of Trust

Units outstanding must be present or represented to have a quorum.

Each Trust unitholder is entitled to one vote for each Trust Unit owned.

Abstentions and broker non-votes shall

not be deemed to be a vote cast.

otherwise required by the Trust Agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the

Trust Units present in person or by proxy at a meeting where there is a quorum.

This is true even if a majority of the total Trust

Units did not approve it.

The affirmative vote of the holders of at least 75% of the outstanding Trust Units is required to:

the Trust Agreement (except with respect to certain matters that do not adversely affect

the rights of Trust unitholders in any material respect);

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

the special meeting of Trust unitholders held on August 30, 2017, unitholders approved amendments to the Trust Agreement.

2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which

amended certain provisions of the Trust Agreement to, among other things, allow Enduro (and, therefore, following the Sale Transaction,

the Sponsor) to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust

unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements

of the Trust Agreement.

This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding

units of the Trust.

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

of Net Profits

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.

Profits Interest

amounts paid to the Trust for the Net Profits Interest are based on, among other things, the definitions of “gross profits”

Abstentions and broker non-votes shall not be deemed to be a vote cast.

Unless otherwise required by the Trust Agreement,

a matter may be approved or disapproved by the affirmative vote of a majority of the Trust Units present in person or by proxy at a meeting

where there is a quorum.

This is true even if a majority of the total Trust Units did not approve it.

The affirmative vote of the holders

of at least 75% of the outstanding Trust Units is required to:

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);

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

At the special meeting of Trust unitholders held

on August 30, 2017, unitholders approved amendments to the Trust Agreement.

In September 2017, Enduro, the Trustee and the Delaware Trustee

entered into the First Amendment to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to,

among other things, allow Enduro (and, therefore, following the Sale Transaction, the Sponsor) to sell interests in the Underlying Properties

free and clear of the Net Profits Interest with the approval of Trust unitholders holding at least 50% of the then outstanding units of

the Trust at a meeting held in accordance with the requirements of the Trust Agreement.

This amendment reduced the required threshold

for approval of such sales from 75% to 50% of the outstanding units of the Trust.

In addition, certain amendments to the Trust Agreement

may be made by the Trustee without approval of the Trust unitholders.

Computation of Net Profits

The provisions of the Conveyance governing the

computation of the net profits are detailed and extensive.

The following information summarizes the material provisions of the Conveyance

related to the computation of the net profits, but is qualified in its entirety by the text of the Conveyance, which is incorporated by

reference as an exhibit to this Form 10-K.

Net Profits Interest

The amounts paid to the Trust for the Net Profits

Interest are based on, among other things, the definitions of “gross profits”

and “net profits”

contained in the Conveyance and described below.

Under the Conveyance, net profits are computed

monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties

for each calendar month will be paid to the Trust on or before the end of the following month.

The Sponsor will not pay to the

Trust any interest on the net profits held by the Sponsor prior to payment to the Trust, provided that such payments are timely

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.

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):

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;

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;

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;

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;

amounts and other consideration for (i) rent and the use of or damage to the surface,

(ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal,

extension, modification, amendment, replacement or supplementation of the leases included

in the Underlying Properties;

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 the Sponsor’s operations with respect thereto;

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

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

all amounts and other consideration for (i) rent and the use of or damage to the surface, (ii) delay rentals, shut-in well

payments 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 the Sponsor’s 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;

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;

costs and expenses for recording the Conveyance and, at the applicable times, terminations

and/or releases thereof;

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

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).

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.

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;

the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period,

and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for

purposes of determining the net profits for that following computation period.

Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses

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

Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the

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

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;

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;

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

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).

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.

Sponsor will have no further obligations, requirements or responsibilities with respect to any such transferred interests.

addition, the Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest

associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties

in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period,

an aggregate fair market value to the Trust of $500,000.

These releases will be made only in connection with a sale by the Sponsor

to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the Trust

of such Net Profits Interest being treated as an offset amount against costs and expenses.

In January 2019, the Sponsor sold two

producing wells and associated acreage of the Underlying Properties under this provision for a sale price of approximately $62,000,

and the Trustee released such properties from the Net Profits Interest.

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

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;

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

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.

expects to make distributions to Trust unitholders monthly;

however, in the event that the net profits for any computation period is a

negative amount, the Trust will receive no payment for that period, and any such negative amount plus accrued interest will be deducted

from gross profits in the following computation period for purposes of determining the net profits for that following computation period.

The Trust uses the modified cash basis of accounting

to report Trust receipts of the Net Profits Interest and payments of expenses incurred.

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 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;

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 Sponsor may enter into any of these agreements without the consent or approval of the Trustee

or any Trust unitholder.

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).

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.

Sponsor must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the Trust.

Monthly and annually, the Sponsor must deliver to the Trustee a statement of the computation of the net profits for each computation

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.

The Trust unitholders are not entitled to any proceeds of a sale or transfer of the Sponsor’s interest.

Except in certain cases where the Net Profits Interest is released, following a sale or transfer, the Underlying Properties will continue

to be subject to the Net Profits Interest, and the gross profits attributable to the transferred property will be calculated, paid and

distributed by the transferee to the Trust.

The Sponsor will have no further obligations, requirements or responsibilities with respect

to any such transferred interests.

In addition, the Sponsor may, without the consent

of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with any lease that accounts for less than

or equal to 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest

covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000.

These releases

will be made only in connection with a sale by the Sponsor to a non-affiliate of the relevant Underlying Properties and are conditioned

upon an amount equal to the fair value to the Trust of such Net Profits Interest being treated as an offset amount against costs and expenses.

In September 2021, the Sponsor entered into a lease arrangement with respect to a portion of the mineral rights relating to certain

of the Underlying Properties located in Borden County, Texas, for total estimated proceeds of $82,500 (approximately $63,000 net to the

Trust’s 80% Net Profits Interest).

As the designated operator of a property included

in the Underlying Properties, the Sponsor may enter into farm-out, operating, participation and other similar agreements to develop the

property, but any transfers made in connection with such agreements will be made subject to the Net Profits Interest.

The Sponsor may

enter into any of these agreements without the consent or approval of the Trustee or any Trust unitholder.

The Sponsor has the right to release, surrender

or abandon its interest in any Underlying Property that will no longer produce (or be capable of producing) hydrocarbons in paying quantities

(determined without regard to the Net Profits Interest).

Upon such release, surrender or abandonment, the portion of the Net Profits Interest

relating to the affected property will also be released, surrendered or abandoned, as applicable.

The Sponsor also has the right to abandon

an interest in the Underlying Properties if (a) such abandonment is necessary for health, safety or environmental reasons or (b) the

hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be expected to be

produced from wells located on the remaining portion of the Underlying Properties.

The Sponsor must maintain books and records

sufficient to determine the amounts payable for the Net Profits Interest to the Trust.

Monthly and annually, the Sponsor must

deliver to the Trustee a statement of the computation of the net profits for each computation period.

The Trustee has the right to

inspect and review the books and records maintained by the Sponsor during normal business hours and upon reasonable notice.

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.

Federal Income Tax Matters

following is a summary of certain U.S.

federal income tax matters that may be relevant to the Trust unitholders.

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.

summary has limited application to non-U.S.

The following is a summary of certain U.S.

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:

1 unchanged sentence

Trust unitholders subject to the alternative minimum tax;

organizations;

tax-exempt organizations;

dealers in securities or commodities;

regulated investment companies;

regulated investment

real estate investment trusts;

securities that elect to use a mark-to-market method of accounting for their securities holdings;

Trust unitholders that

are “controlled foreign corporations”

traders in securities that elect to use a mark-to-market method of accounting for their securities

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;

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;

Trust unitholders whose functional currency

is not the U.S.

persons who hold the Trust Units as a position in a hedging transaction, “straddle”, “conversion

transaction”

Trust unitholders whose

functional currency is not the U.S.

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

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.

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.

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.

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.

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.

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.

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 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.

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.

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.

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 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.

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

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

Classification

of the Net Profits Interest

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.

Requirements for Widely-Held Fixed Investment Trusts

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.

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

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.

Trust Tax Information

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.

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

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

These laws and regulations may impose significant obligations on the Sponsor’s operations, including requirements

permits to conduct regulated activities;

or prohibit drilling activities on certain lands lying within wilderness, wetlands and

other protected areas;

the types, quantities and concentration of materials that can be released into the environment

in the performance of drilling, completion and production activities;

investigatory and remedial measures to mitigate pollution from former or current operations,

such as restoration of drilling pits and plugging of abandoned wells;

specific health and safety criteria addressing worker protection.

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.

Sponsor may be unable to pass on those increases to its customers.

Environmental Matters and Regulation

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;

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.

following is a summary of certain existing environmental, health and safety laws and regulations to which the Sponsor’s

business operations are subject.

substance and wastes.

The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,”

known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original

conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance”

of the Sponsor’s operations, and there can be no assurance that the Sponsor will not incur significant costs and liabilities as

a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.

The following is a summary of certain existing

environmental, health and safety laws and regulations to which the Sponsor’s business operations are subject.

Hazardous substance and wastes.

The Comprehensive

Environmental Response, Compensation and Liability Act, or “CERCLA,”

also known as the Superfund law, and comparable state

laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered

to be responsible for the release of a “hazardous substance”

into the environment.

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 include the owner or operator of the site where

the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances

released at the site.

These responsible persons may be subject to joint and several strict liability for the costs of cleaning

up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of

certain health studies.

CERCLA also authorizes the U.S.

Environmental Protection Agency (“EPA”) and, in some instances,

third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible

classes of persons the costs they incur.

It is not uncommon for neighboring landowners and other third parties to file claims

for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

generates materials in the course of its operations that may be regulated as hazardous substances.

Resource Conservation and Recovery Act, or “RCRA,”

and comparable state laws regulate the generation, transportation,

treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes.

Under the auspices of the EPA, most states administer

some or all the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements.

Drilling fluids, produced

waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are

currently regulated under the RCRA as non-hazardous wastes.

Nevertheless, it is possible that certain oil and natural gas exploration

and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in

For example, in December 2016, the EPA and environmental groups entered a consent decree to address the EPA’s

alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related

oil and natural gas wastes from regulation as hazardous wastes under RCRA.

The consent decree required the EPA to propose a rulemaking

no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes

or to sign a determination that revision of the regulations is not necessary.

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.

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.

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 generates materials in the course of its operations that may

be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

The Resource Conservation and Recovery Act, or

“RCRA,”

and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous

and non-hazardous wastes.

Under the auspices of the EPA, most states administer some or all the provisions of RCRA, sometimes in conjunction

with their own, more stringent requirements.

Drilling fluids, produced waters and most of the other wastes associated with the exploration,

production and development of crude oil or natural gas are currently regulated under the RCRA as non-hazardous wastes.

Nevertheless, it

is possible that certain oil and natural gas exploration and production wastes (“E&P Wastes”) now classified as non-hazardous

could be classified as hazardous wastes in the future.

For example, in December 2016, the EPA and environmental groups entered a consent

decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration

and production-related oil and natural gas wastes from regulation as hazardous wastes under RCRA.

The consent decree required the EPA

to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural

gas wastes or to sign a determination that revision of the regulations is not necessary.

The EPA fulfilled its obligation under the consent

decree by issuing a determination on April 23, 2019 that revisions to existing RCRA Subtitle D regulations governing oil and natural

gas wastes are not necessary, along with a report supporting that determination.

In addition, the Sponsor generates industrial

wastes in the ordinary course of its operations that may be regulated as hazardous wastes.

Such wastes must be properly tested,

characterized and disposed of according to state and federal regulations.

properties upon which the Sponsor conducts its operations have been used for oil and natural gas exploration and production for

Although the Sponsor and, as applicable, the Sponsor’s predecessor, Enduro, may have utilized operating and

disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of

or released at or from the real properties upon which the Sponsor conducts its operations, or at or from other, offsite locations,

where these petroleum hydrocarbons and wastes have been taken for recycling or disposal.

In addition, the properties upon which

the Sponsor conducts its operations may have been operated by third parties or by previous owners or operators whose treatment

and disposal of hazardous substances, wastes or hydrocarbons was not under the Sponsor’s control.

These properties and the

petroleum hydrocarbons and wastes disposed or released at or from these properties may be subject to CERCLA, RCRA and analogous

Under such laws, the Sponsor could be required to investigate, remove or remediate previously disposed wastes, to

clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells

decree by issuing a determination on April 23, 2019 that revisions to existing RCRA Subtitle D regulations governing oil and natural gas

wastes are not necessary, along with a report supporting that determination.

In addition, the Sponsor generates industrial wastes in the

ordinary course of its operations that may be regulated as hazardous wastes.

Such wastes must be properly tested, characterized and disposed

of according to state and federal regulations.

The properties upon which the Sponsor conducts

its operations have been used for oil and natural gas exploration and production for many years.

Although the Sponsor and, as applicable,

the Sponsor’s predecessor, Enduro, may have utilized operating and disposal practices that were standard in the industry at the

time, 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.

properties and wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws.

Under these laws, the Sponsor could be

required to investigate, remove or remediate previously disposed wastes, to clean up contaminated property and to perform response actions

to prevent future contamination or to pay some or all of the costs of any such action.

The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls

regarding the discharge of pollutants into water of the United States and waters of the state, respectively.

Pursuant to the CWA

and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States.

such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA

or the analogous state agency.

The discharge of wastewater from most onshore oil and gas activities 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”)

Water discharges.

The federal Clean Water

Act (“CWA”) and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into water

of the United States and waters of the state, respectively.

Pursuant to the CWA and analogous state laws, permits must be obtained to

discharge pollutants into state waters or waters of the United States.

Any such discharge of pollutants into regulated waters must be

performed in accordance with the terms of the permit issued by EPA or the analogous state agency.

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.

discharge of dredge and fill material in waters of the United States, including wetlands, is also prohibited unless authorized

by a permit issued by the U.S.

Army Corps of Engineers (“ACE”).

CWA Section 401 provides that the applicant for an

individual Section 404 ACE permit for the discharge of dredge and fill materials must notify the state in which the discharge

will occur and provide an opportunity for the state to determine if the discharge will comply with the state’s approved

water quality program.

In some instances, this process could result in delay in issuance of the permit, more stringent permit

requirements, or denial of the permit.

the EPA and the ACE define “waters of the United States”

(“WOTUS”) can impact the Sponsor’s regulatory

and permitting obligations under the CWA.

The EPA and the ACE promulgated rules defining the scope of WOTUS that became effective

in September 2015.

On October 22, 2019, the EPA and the ACE published a final rule that repealed the 2015 definition of WOTUS

and re-codified longstanding regulatory definitions of WOTUS that existed prior to the 2015 rule to promote regulatory consistency

across the United States.

On April 21, 2020, the EPA and the ACE issued a revised regulation (the “2020 rule”) that

narrowed the definition from the 2015 rule.

Litigation has been filed on the 2020 rule, but it is currently effective in all jurisdictions.

In January 2021, President Biden issued an Executive Order announcing that the new administration would review the 2020 rule,

and the administration has asked that litigation on the 2020 rule be stayed while it considers how to proceed.

To the extent that

the Sponsor must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other WOTUS,

the Sponsor could face increased costs and delays associated with obtaining such permits under any broader definition of WOTUS

that expands the scope of CWA jurisdiction.

Oil Pollution Act of 1990, as amended, or OPA, amends the CWA and establishes strict liability and natural resource damages liability

for unauthorized discharges of oil into waters of the United States.

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

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.

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.

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.

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.

Corps of Engineers (“USACE”).

CWA Section 401 provides that the applicant for an individual Section 404 USACE permit for the

discharge of dredge and fill materials must notify the state in which the discharge will occur and provide an opportunity for the state

to determine if the discharge will comply with the state’s approved water quality program.

In some instances, this process could

result in delay in issuance of the permit, more stringent permit requirements, or denial of the permit.

How the EPA and the USACE define

“waters of the United States”

(“WOTUS”) , which defines the extent of geographic jurisdiction under the CWA,

can impact the Sponsor’s regulatory and permitting obligations under the CWA.

In 2020, the EPA and the USACE issued a final

rule (“2020 rule”) that narrowed the definition of WOTUS when compared to the prior definition of WOTUS that had been

adopted in 2015.

In August 2021, however, a court vacated the 2020 rule.

In response, the EPA and the USACE reverted to the WOTUS

definition in use prior to the 2015 WOTUS rulemaking.

That pre-2015 definition is broader than the definition from the 2020 rule,

but was never formally codified because it was based on interpretation of a U.S.

Supreme Court decision.

On December 7, 2021, the

agencies published a proposed rule that would codify the interpretation currently in use.

The comment period closed in February 2022

and a final rule is expected later in 2022.

At the same time, the U.S.

Supreme Court has taken up a case that may again revise the

understanding of the WOTUS definition.

The Sponsor’s regulatory obligations and permitting costs may increase under the

current definition as opposed to the one in effect under the 2020 rule, and there will remain some uncertainty around the definition

of WOTUS and the scope of CWA regulation, given expected challenges to the 2022 final rule and the pending Supreme Court case.

USACE Nationwide Permits (“NWPs”) are

a streamlined form of permitting used to authorize development activities with minimal individual or cumulative adverse effects in wetlands

or other waters of the United States under the CWA and/or Rivers and Harbors Act.

The current administration has stated an intention

to re-visit all or some of the USACE NWPs before their current expiration date of February 2026.

In addition, a federal court in

Montana is currently hearing a challenge to NWP 12, which is used to authorize regulatory impacts related to oil and gas pipelines.

to the NWPs by USACE or an adverse decision in Montana may restrict or remove the ability to use NWP 12 or other NWPs to permit regulated

impacts, resulting in the need to apply for a more time-consuming individual permit.

This could result in additional cost and time for

permitting projects.

Finally, the Oil Pollution Act of 1990, as amended,

or “OPA,”

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;

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

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

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.

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.

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.

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.

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.

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.

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

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

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.

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.

1 unchanged sentence

Properties are located.

The federal Clean Air Act (“CAA”), as amended, and comparable state laws restrict the emission of air

pollutants from many sources through air emissions permitting and regulatory programs and also impose various monitoring and reporting

requirements.

These laws and regulations may require the Sponsor to obtain pre-approval for the construction or modification of

certain projects or facilities expected to produce or significantly increase air emissions, and to comply with stringent air emissions

permit requirements or in utilize specific equipment or technologies to control emissions.

EPA has established pollution control standards for oil and gas sources under the CAA.

In 2012, the EPA adopted federal New Source

Performance Standards (“NSPS”) that require the reduction of volatile organic compound emissions from certain fractured

and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced

emission completions, also known as “green completions.”

These regulations also establish specific new requirements

regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage

EPA is also charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which

can indirectly impact the Sponsor’s operations.

The CAA directs the EPA to review each NAAQS every five years to ensure

that the standards are protective of public health and welfare.

This process routinely results in the tightening of those standards,

and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion.

In December 2020, the EPA published a final

rule that retained without revision the 2015 NAAQS ozone standard.

The new administration will have an opportunity to revisit

the ozone NAAQS.

In addition, on January 20, 2021, President Biden issued an executive order calling on the EPA to propose a Federal

Implementation Plan for the ozone standard for certain states by January 2022, in response to those states’

failure to submit

an adequate state plan for the control of ozone precursor emissions from certain oil and gas sources.

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.

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.

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.

December 2015, the EPA finalized rules that added new sources to the scope of its GHG monitoring and reporting rule.

sources include gathering and boosting facilities.

The revisions also include the addition of well identification reporting requirements

for certain facilities.

In addition, in June 2016 the EPA published a final rule that requires operators to reduce methane emissions

from certain new, modified or reconstructed oil and gas facilities, including production, processing, transmission and storage

activities (“Methane Rule”).

Following the November 2016 presidential election and change in administrations, the

EPA convened a reconsideration proceeding that culminated in a 2020 final rule that eliminated the obligation to control methane

emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements because they serve to

control emissions of other pollutants.

However, on January 20, 2021, President Biden issued an executive order calling on the

EPA to, among other things, consider a proposed rule suspending, revising or rescinding those 2020 amendments to the Methane Rule

by September 2021.

That same order directs the EPA to propose new rules to establish standards of performance and emission guidelines

for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration

and production, transmission, processing, and storage segments, by September 2021.

The ultimate fate of the Methane Rule and any

related requirements for existing sources 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 methane emissions

from its operations.

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 international level, the U.S.

joined the international community at the 21st Conference of the Parties of the United Nations

Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their

contributions and set greenhouse gas emission reduction goals every five years beginning in 2020.

While the Agreement did not

impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements.

Air emissions.

The federal Clean Air Act

(“CAA”), as amended, and comparable state laws and regulations restrict the emission of air pollutants from many sources and

also impose various monitoring and reporting requirements.

These laws and regulations may require the Sponsor to obtain pre-approval for

the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, and to

comply with stringent air emissions permit or regulatory requirements or utilize specific equipment or technologies to control emissions.

Obtaining permits has the potential to delay the development of the Sponsor’s properties.

The EPA has established pollution control standards

for oil and gas sources under the CAA.

In 2012, the EPA adopted federal New Source Performance Standards (“NSPS”) that

require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion

operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.”

These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors,

and from pneumatic controllers and storage vessels.

The EPA is also charged with establishing National

Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact the Sponsor’s operations.

The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare.

This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the ozone NAAQS from 75

to 70 parts per billion.

In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard.

The current administration will have an opportunity to revisit the ozone NAAQS.

In addition, on January 20, 2021, President Biden issued

an executive order calling on the EPA to propose a Federal Implementation Plan for the ozone standard for certain states by January 2022,

in response to those states’

failure to submit an adequate state plan for the control of ozone precursor emissions from certain

oil and gas sources.

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.

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.

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 December 2015, the EPA finalized rules that

added new sources to the scope of its GHG monitoring and reporting rule.

These new sources include gathering and boosting facilities.

The revisions also include the addition of well identification reporting requirements for certain facilities.

In addition, in June 2016

the EPA published a final rule that requires operators to reduce methane emissions from certain oil and gas facilities, that are

constructed, modified, or reconstructed after September 18, 2015 (the “Methane Rule”).

Following the November 2016 presidential

election and change in administrations, the EPA convened a reconsideration proceeding that culminated in a 2020 final rule that eliminated

the obligation to control methane emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements

because they serve to control emissions of other pollutants.

That 2020 final rule, however, was undone by a June 30, 2021 Congressional

Review Act resolution that re-instituted the regulation of methane from new, modified, and reconstructed oil and gas sources.

Additionally,

on November 15, 2021, the EPA published a proposed rule that would 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 GHG control requirements for existing

oil and gas sources 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 methane emissions from its operations.

More than one-third of the states have begun

taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or

regional GHG cap and trade programs.

Although most of the state-level initiatives have to date focused on large sources of GHG emissions,

such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to GHG emission limitations

or allowance purchase requirements in the future.

In addition, from time to time Congress has considered adopting legislation to reduce

emissions of greenhouse gases.

Any one of these climate change regulatory and legislative initiatives could have a material adverse effect

on the Sponsor’s business, capital expenditures, financial condition and results of operations.

At the international level, the U.S.

international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France,

which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals every

five years beginning in 2020.

While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could

have resulted in new regulatory requirements.

In November 2019, however, plans were formally announced for the U.S.

to withdraw from the Paris Agreement, and the U.S.’s

withdrawal from the Paris Agreement took effect on November 4, 2020.

On January 20, 2021, President Biden issued an executive

order commencing the process to reenter the Paris Agreement, although the emissions pledges in connection with that effort have

not yet been updated.

to withdraw from the

Paris Agreement, and the U.S.’s withdrawal from the Paris Agreement took effect on November 4, 2020.

On January 20, 2021, President

Biden issued an executive order commencing the process to reenter the Paris Agreement, although the emissions pledges in connection with

that effort have not yet been updated.

formally rejoined the Paris Agreement in February 2021.

The Trust cannot predict whether re-entry

into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements

The Trust cannot predict whether

re-entry into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements

will cause the Sponsor to incur material costs.

a separate executive order issued on January 20, 2021, President Biden asked the heads of all executive departments and agencies

to review and take action to address any Federal regulations, orders, guidance documents, policies and any similar agency actions

promulgated during the prior administration that may be inconsistent with or present obstacles to the administration’s stated

goals of protecting public health and the environment, and conserving national monuments and refuges.

A preliminary list must

be provided to the Office of Management and Budget within 30 days of the order.

Regulations specifically mentioned for review

and possible suspension, revision or rescission include the Methane Rule, and the EPA was ordered to, among other things, propose

new regulations to establish comprehensive standards for performance and emission guidelines for methane from existing oil and

gas operations by September 2021.

The executive order also established an Interagency Working Group on the Social Cost of Greenhouse

Gases, which is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social

cost of carbon,”

In a separate executive order issued on January

20, 2021, President Biden asked the heads of all executive departments and agencies to review and take action to address any Federal regulations,

orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent

with or present obstacles to the administration’s stated goals of protecting public health and the environment, and conserving national

monuments and refuges.

The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which

is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social cost of carbon,”

“social cost of nitrous oxide”

and “social cost of methane,”

which are “the

monetized damages associated with incremental increased in greenhouse gas emissions,”

including “changes in net agricultural

productivity, human health, property damage from increased flood risk, and the value of ecosystem services.”

Various recommendations

from the Working Group are due beginning June 1, 2021 and final recommendations no later than January 2022.

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.

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

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.

Environmental Policy Act.

Oil and natural gas exploration, development and production activities on federal lands are subject

to the National Environmental Policy Act, as amended (“NEPA”).

NEPA requires federal agencies, including the Department

of the Interior, to evaluate major agency actions having the potential to significantly impact the environment.

In the course

of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative

impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made

available for public review and comment.

However, for those current activities as well as for future or proposed exploration and

development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required.

This process has the potential to delay the development of oil and natural gas projects.

The federal Endangered Species Act and similar state statutes restrict activities that may affect endangered

and threatened species or their habitats.

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, delayed or expensive

mitigation may be required.

On August 27, 2019, the U.

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

The designation of previously unidentified endangered or threatened species could cause the Sponsor to incur additional

costs arising from species protection measures or could result in limitations on exploration and production activities that could

have an adverse impact on the ability to develop and produce reserves from the Underlying Properties.

health and safety.

The operations of the Sponsor are subject to a number of federal and state laws and regulations, including

the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect

the health and safety of workers.

In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations

under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information

be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees,

state and local government authorities and citizens.

You Can Find Other Information

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.

the Trust will provide electronic copies of its recent filings free of charge to the Trust unitholders upon request to the Trustee.

which are “the monetized damages associated

with incremental increased in greenhouse gas emissions,”

including “changes in net agricultural productivity, human health,

property damage from increased flood risk, and the value of ecosystem services.”

The Working Group is expected to issue its recommendations

in early 2022.

The adoption and implementation of regulations

imposing reporting obligations on, or limiting emissions of GHGs from, the Sponsor’s equipment and operations could require the

Sponsor to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the natural gas

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.

Environmental Policy Act (“NEPA”) requires the federal government to undertake an environmental review prior to making a decision

on most proposed federal actions –

such as permits, leases, and rights-of-way.

The Trump Administration significantly revised

the regulations implementing NEPA in 2020 in an effort to make the review process more efficient and more narrowly tailored to the agency’s

specific action.

The Biden Administration is in the process of an initial revision to the NEPA regulations, and in October 2021 the

White House Council on Environmental Quality (“CEQ”) published a proposed rule that would undo many of the changes adopted

The current administration has also stated its intention to undertake a second and more comprehensive round of revisions.

immediate changes may not have a significant impact on federal reviews related to the Sponsor’s actions because the Trump Administration

rule was never fully implemented by the agencies;

however, continued change may increase agency review times associated with federal actions

as agencies adjust to changing requirements and react to any resulting litigation.

Endangered Species Act.

The federal Endangered

Species Act, as amended (“ESA”), restricts activities that may affect endangered and threatened species or their habitats.

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, delayed or expensive mitigation may be required.

On August 27, 2019, the U.S.

Wildlife Service published a final rule adopting several changes to the federal regulations that implement the ESA, including changes

to the procedures and criteria for listing or removing species from the Lists of Endangered and Threatened Wildlife and Plants and for

designating critical habitat.

In January 2021, President Biden issued an Executive Order announcing that the new administration would

initiate a review of the 2019 amendments to the ESA rules.

The Biden Administration has rescinded one of the rules adopted by the prior

administration, dealing with critical habitat, and has stated its intention to revise other rules.

Changes to these rules could make a

federal review process occasioned by the application for permits, rights of way, or leases more complex.

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.

addition, the OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund

Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials

used or produced in operations and that this information be provided to employees, state and local government authorities and citizens.

Where You Can Find Other Information

The Trust maintains a website at http://www.permianvilleroyaltytrust.com.

The Trust’s filings under the Exchange Act are available at this website and are also available electronically from the website

maintained by the SEC at http://www.sec.gov.

In addition, the Trust will provide electronic copies of its recent filings free of charge

to the Trust unitholders upon request to the Trustee.

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business