What changed in this filing

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Item 1. Business

2023-03-23 compared with 2022-03-25 · 584 added, 597 removed, 432 unchanged (73% of the section changed)

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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

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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,

In July 2018, Enduro entered into a purchase

and sale agreement with COERT Holdings 1 LLC (“COERT”

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

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

the Sale Transaction.

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

and other instruments to which Enduro and the Trustee were parties.

COERT is a Delaware limited liability company engaged in the production

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

and the Arklatex region of Texas and Louisiana.

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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.

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

The Net Profits Interest is passive in nature

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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.

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.

In connection with the formation of the Trust,

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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.

of the Trustee’s intent to build a reserve for the payment of future known, anticipated or contingent expenses or liabilities of

Since February 2022, the Trustee has been withholding $37,833, and in the future, commencing with the distribution to

Trust unitholders payable in April 2023, intends to withhold $50,000, from the funds otherwise available for distribution each month

to gradually build a cash reserve of approximately $2.3 million.

This 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.

As of December 31, 2022, the Trust has withheld a cumulative balance

Each month, the Trustee pays Trust obligations

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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

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.

The Trust is not subject

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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

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.

Upon dissolution of the Trust,

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Year Ended December 31,

ConocoPhillips

Occidental Petroleum

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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.

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

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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

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.

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

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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

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.

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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 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.

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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.

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

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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

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

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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.

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

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

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

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

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

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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).

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).

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 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

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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.

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

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and “net profits”

contained in the

Conveyance and described below.

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.

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 ”

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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

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.

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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.

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 ”

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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;

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.

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 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).

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.

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

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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

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.

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Additional Provisions

If a controversy arises as to the sales price of

any production, then for purposes of determining gross profits:

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

that the proceeds are actually collected;

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

to the Sponsor by the escrow agent;

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

If 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.

The Trustee is not obligated to return any cash

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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).

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

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

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(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.

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

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

The Sponsor also has the right

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

or (b) the hydrocarbons that would have been produced from the abandoned portion of the Underlying Properties would reasonably be

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

The Sponsor must maintain books and records sufficient

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

Monthly and annually, the Sponsor must deliver to the Trustee

a statement of the computation of the net profits for each computation period.

The Trustee has the right to inspect and review the books

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

The Sponsor has further agreed to provide

the Trust and Trustee with all information and services as are reasonably necessary to fulfill the purposes of the Trust, including such

accounting, bookkeeping and informational services as may be necessary for the preparation of reports the Trust is required to prepare

or file in accordance with applicable tax and securities laws, exchange listing rules and other requirements, including reserve

reports and tax returns.

Following the sale of all or any portion of the Underlying Properties, the purchaser will be bound by the obligations

of the Sponsor under the Trust Agreement and the Conveyance with respect to the portion sold.

Federal Income Tax Matters

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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.

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

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.

3 unchanged sentences

Rather, each Trust unitholder is considered for U.S.

federal income tax purposes to own its proportionate share of the Trust’s assets

directly as though no Trust were in existence.

The income of the Trust is deemed to be received or accrued by the Trust unitholder at

the time such income is received or accrued by the Trust, rather than when distributed by the Trust.

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

8 unchanged sentences

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.

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

federal income tax rate applicable to long-term capital gai ns (generally, gains from the sale or exchange of certain investment

assets held for more than one year) and qualified dividends of individuals is generally 20%.

Such marginal tax rates may be effectively

increased due to the phaseout of personal exemptions and certain limitations and prohibitions on itemized deductions.

The highest marginal

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

11 unchanged sentences

(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.

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.

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.

Tax counsel to the Trust advised the Trust at

the time of formation that, for U.S.

federal income tax purposes, based upon the reserve report and representations made by the Trust

regarding the expected economic life of the Underlying Properties and the expected duration of the Net Profits Interest, in its opinion

the Net Profits Interest attributable to proved developed reserves will and the Net Profits Interest attributable to proved undeveloped

reserves should be treated as continuing, nonoperating economic interests in the nature of royalties payable out of production from the

mineral interests they burden.

No assurance can be given that the IRS or another taxing authority will not assert that the Net Profits

Interest should be treated differently.

Any such different treatment could affect the amount, timing and character of income, gain or

loss in respect of an investment in Trust Units.

Reporting Requirements for Widely-Held Fixed Investment Trusts

The Trustee assumes that some Trust Units are held

by middlemen, as such term is broadly defined in the Treasury regulations (and includes custodians, nominees, certain joint owners and

brokers holding an interest for a custodian street name, collectively referred to herein as “middlemen”).

Therefore, the Trustee

considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S.

federal income tax purposes.

The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Houston, Texas 77002, telephone number 1-512-236-6545, is the representative

of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing the information reporting

requirements of the Trust as a WHFIT.

Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of unitholders, and not

the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations

with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements.

Unitholders whose Trust

Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen

with respect to the Trust Units.

Any generic tax information provided by the Trustee of the Trust is intended to be used only to assist

Trust unitholders in the preparation of their federal and state income tax returns.

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”).

the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S.

federal income

tax purposes.

The Bank of New York Mellon Trust Company, N.A., 601 Travis Street, Houston, Texas 77002, telephone number 1-512-236-6545,

is the representative of the Trust that will provide the tax information in accordance with applicable Treasury regulations governing

the information reporting requirements of the Trust as a WHFIT.

Notwithstanding the foregoing, the middlemen holding Trust Units on behalf

of unitholders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under

the Treasury regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements.

Unitholders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported

to them by the middlemen with respect to the Trust Units.

Any generic tax information provided by the Trustee of the Trust is intended

to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.

Available Trust Tax Information

In compliance with the Treasury regulations reporting

requirements for WHFITs and the dissemination of Trust tax reporting information, the Trustee provides a generic tax information reporting

booklet which is intended to be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.

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 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.

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.

and regulations may impose significant obligations on the Sponsor’s operations, including requirements to:

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.

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.

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

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”

substance and wastes.

The Comprehensive Environmental Response, Compensation and Liability Act, (“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.

These persons include current and prior owners or operators of the site where the release occurred and entities that disposed or arranged

for the disposal of the hazardous substances found at the site.

Under CERCLA, these “responsible persons”

may be liable for the costs of cleaning up the hazardous substances

that have been released into the environment, for damages to natural resources, and for the costs of certain health studies.

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.

may be liable for

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

for the costs of certain health studies.

CERCLA also authorizes the U.S.

Environmental Protection Agency (“EPA”) and, in

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

classes of persons the costs they incur.

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

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

Although petroleum, natural gas,

and natural gas liquids are excluded from the definition of “hazardous substance”

under CERCLA, the Sponsor generates materials

in the course of its operations that may be regulated as CERCLA hazardous substances, despite the so-called “petroleum exclusion.”

Resource Conservation and Recovery Act (“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

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.

The properties upon which the Sponsor conducts

6 unchanged sentences

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.

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.

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

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

Under these laws, the Sponsor could

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

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

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

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

Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge requirements may

result in increased costs.

can either discharge treated water directly to surface waters or send it to a POTW.

In 2018, the EPA concluded a study of the treatment

and discharge of oil and gas wastewater that could lead to changes in requirements for discharge of produced water under Part 437,

including more stringent requirements or a prohibition on discharge of produced water from CWT facilities.

Any restriction of disposal

options for hydraulic fracturing waste and other changes to CWA discharge requirements may result in increased costs.

The discharge of dredge and fill material in waters

of the United States, including wetlands, is also prohibited unless authorized by a permit issued under CWA Section 404 by the U.S.

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.

Army 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 2023, the EPA and the USACE issued a final rule (“2023

rule”) that is described by the EPA and the USACE as following the 1986 regulations as modified by subsequent U.S.

Supreme Court

decisions and guidance issued by the EPA and USACE interpreting the decisions.

The 2023 rule is already subject to litigation, including

motions for preliminary injunctions to prevent the 2023 Rule from going into effect.

One issue raised in the litigation is that

Supreme Court decision in the Sackett II case is expected in mid-2023 and will likely address the definition of wetlands in the

The Sponsor’s regulatory obligations and permitting costs will continue to be subject to remaining uncertainty around

the definition of WOTUS and the scope of CWA regulation, given the pending litigation over the 2023 Rule and expected Supreme Court

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 NWP 12, which is used to authorize regulated impacts related to construction of oil and gas pipelines,

through notice and comment rulemaking before its current expiration date of February 2026.

In addition, a federal court in

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.

Several states, trade groups and companies have challenged the legality of the BLM rule in federal court.

Washington, D.C.

is currently hearing a challenge to NWP 12.

Revisions to NWP 12 by USACE or an adverse decision in Washington,

may restrict or remove the ability to use NWP 12 to permit regulated impacts, resulting in the need to apply for a more time-consuming

individual permit.

This could result in additional cost and time for permitting projects.

the Oil Pollution Act of 1990, as amended (“OPA”), which amends the CWA, establishes standards for prevention, containment

and cleanup of oil spills into waters of the United States.

The OPA requires measures to be taken to prevent the accidental discharge

of oil into waters of the United States from onshore production facilities.

Measures under the OPA and/or the CWA include inspection

and maintenance programs to minimize spills from oil storage and conveyance systems;

the use of secondary containment systems to prevent

spills from reaching nearby waterbodies;

proof of financial responsibility to cover environmental cleanup and restoration costs that

could be incurred in connection with an oil spill;

and the development and implementation of spill prevention, control and countermeasure

(“SPCC”) plans to prevent and respond to oil spills.

The OPA also subjects owners and operators of facilities in certain

instances to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill.

The Sponsor has developed and implemented SPCC plans for the Underlying Properties as required under the CWA.

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.

In addition, the federal government

is currently undertaking several studies of hydraulic fracturing’s potential impacts.

The Secretary of Energy Advisory Board published

their ninety-day report that included a number of recommendations.

In December 2016, the EPA issued a final report on the potential

impacts of hydraulic fracturing on drinking water resources.

The report did not find widespread, systematic impacts to drinking water

from hydraulic fracturing;

at the same time, the report acknowledged information gaps that limited EPA’s ability to fully assess

the potential impacts to drinking water resources.

In addition, as noted above, the EPA in June 2016 issued a final rule implementing

wastewater pretreatment standards that prohibit onshore unconventional oil and gas extraction facilities from sending wastewater directly

EPA is conducting a related study of oil and gas extraction wastewater at private wastewater treatment facilities.

In March 2015,

the federal Bureau of Land Management (“BLM”) released a final rule establishing new or more stringent standards for

performing hydraulic fracturing operations on federal and tribal lands.

Several states, trade groups and companies have challenged the

legality of the BLM rule in federal court.

On September 30, 2015, the U.S.

District Court for the District of Wyoming issued a preliminary injunction, blocking BLM from enforcing the new rules nationwide, and

on June 21, 2016, the court issued a final ruling striking down the BLM rule.

District Court for the District of Wyoming issued

a preliminary injunction, blocking BLM from enforcing the new rules nationwide, and on June 21, 2016, the court issued a final

ruling striking down the BLM rule.

While the U.S.

Department of Interior initially has appealed

the decision to the Tenth Circuit Court of Appeals.

Department of Interior initially has appealed the decision to the Tenth Circuit Court

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 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.

Similar measures could be considered or implemented in the jurisdictions in which the Underlying

Properties are located.

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.

EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court

challenges to the rules were also filed.

In response to some of these challenges, the EPA amended the rule to extend compliance

dates for certain storage vessels and may issue additional revised rules in response to additional such requests in the future.

Only a portion of these new rules appear to affect the Sponsor’s operations at this time by requiring new air emissions controls,

equipment modification, maintenance, monitoring, recordkeeping and reporting.

Although these new requirements will increase the Sponsor’s

operating and capital expenditures and it is possible that the EPA will adopt further regulation that could further increase the Sponsor’s

operating and capital expenditures, the Sponsor does not currently expect such existing and new regulations will have a material adverse

impact on its operations or financial results.

states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements relating

to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used in the hydraulic

fracturing process.

Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process

to state or federal regulatory authorities who could then make such information publicly available.

Disclosure of chemicals used in the

fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers

and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.

In addition, if hydraulic fracturing is regulated at the federal level, the Sponsor’s and the third-party operators’

fracturing activities could become subject to additional permit requirements or operational restrictions, to associated permitting delays

and potential increases in costs.

In December 2014, the Governor of New York announced that the state would maintain its moratorium

on hydraulic fracturing in the state.

Further, some local governments, including in Texas, have imposed moratoria on drilling permits

within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities.

Similar measures could

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

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.

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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.

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

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

completions.”

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

reciprocating compressors, and from pneumatic controllers and storage vessels.

In June 2016, the EPA published a second NSPS for

oil and gas sources that requires operators to reduce volatile organic compound (and methane) emissions from certain oil and gas

facilities, including production, processing, transmission and storage activities, that are constructed, modified, or reconstructed after

September 18, 2015.

More recently, the EPA issued a November 15, 2021 proposal and a November 11, 2022 supplemental proposal

that would establish volatile organic compound and methane emissions standards for oil and gas sources that are constructed, modified,

or reconstructed after November 15, 2021, as well as a set of volatile organic compound and methane emissions guidelines that would

apply to existing oil and gas sources for the first time under the CAA.

The EPA plans to issue a final rule from the pending proposal

The EPA is also charged with establishing National

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to 70 parts per billion.

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

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

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 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

In December 2015, the EPA finalized rules that

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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.

More recently, the EPA issued

a November 15, 2021 proposal and a November 11, 2022 supplemental proposal that would establish volatile organic compound and

methane emissions standards for oil and gas sources that are constructed, modified, or reconstructed after November 15, 2021, as

well as a set of volatile organic compound and methane emissions guidelines that would apply to existing oil and gas sources for the

first time under the CAA.

The EPA plans to issue a final rule from the pending proposal in 2023, 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

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.

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

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

will cause the Sponsor to incur material costs.

The Trust cannot predict whether re-entry into the Paris Agreement or pledges made in connection therewith will result in new regulatory

requirements or whether such requirements will cause the Sponsor to incur material costs.

In a separate executive order issued on January 20,

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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,”

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”

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which are “the monetized damages associated

with incremental increased in greenhouse gas emissions,”

with incremental increases 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.

In late 2022, the Working Group proposed to significantly

increase the social cost of carbon used in assessing the costs and benefits of government actions.

The adoption and implementation of regulations

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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 –

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.

The National Environmental Policy Act (“NEPA”) requires the federal government to undertake

an environmental review prior to making a decision on most proposed federal actions –

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

The Trump Administration significantly revised

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

specific action.

The Biden Administration is in the process 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

Trump Administration significantly revised the regulations implementing NEPA in 2020 in an effort to make the review process more efficient

and more narrowly tailored to the agency’s specific action.

The Biden Administration undertook an initial revision to the

NEPA regulations which were finalized in 2022, essentially reverting to the pre-2020 rule language for a few elements of the rules.

The White House Council on Environmental Quality (“CEQ”) is expected to publish a round-two rulemaking in early 2023 that

will make more significant revisions to the Trump-era rule.

In addition, in early 2023 CEQ issued Guidance to the federal agencies on

how agencies should consider greenhouse gas emissions and climate impacts in the course of their reviews under NEPA.

The 2022 regulatory

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.

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

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

The federal Endangered Species Act, as amended (“ESA”), restricts or prohibits 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.

Fish and Wildlife Service published a final rule adopting several

changes to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing species

from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat.

In January 2021, President

Biden issued an Executive Order announcing that the new administration would initiate a review of the 2019 amendments to the ESA rules.

The Biden Administration has rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and

has stated its intention to revise other rules, but that has not yet occurred.

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.

health and safety.

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

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

the health and safety of workers.

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

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

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

authorities and citizens.

Where You Can Find Other Information

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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