What changed in this filing

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Item 1. Business

2024-03-22 compared with 2023-03-23 · 431 added, 401 removed, 615 unchanged (57% of the section changed)

Permianville Royalty Trust (the “Trust”),

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

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

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

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

and restated, and as further amended, the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”), as

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

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

Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for

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This amendment reduced the required threshold for approval

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

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

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

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

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

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

To effect the same changes as those included in the

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

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

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

(the “Partial Release”).

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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 Transaction.

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

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

COERT is a Delaware limited liability company engaged in the production

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

and the Arklatex region of Texas and Louisiana.

References to “COERT”

or the “Sponsor”

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

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

On August 31, 2018, COERT Holdings 1 LLC

(“COERT”

or the “Sponsor”) acquired the Underlying Properties and all of the outstanding Trust Units owned by

Enduro (the “Sale Transaction”).

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

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

COERT is a Delaware limited liability company

engaged in the production and development of oil and natural gas from properties located in the Rockies, the Permian Basin of west Texas

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

On May 3, 2023, the Sponsor notified the

Trustee that the Sponsor had entered into an agreement to divest certain acreage and associated production in the Permian Basin (the

“2023 Divestiture Properties”) that constituted part of the Underlying Properties and were therefore burdened by the Trust’s

Net Profits Interest, for a total purchase price of approximately $6.7 million.

On July 19, 2023, at a special meeting of Trust

unitholders, the unitholders approved the foregoing transaction and the release of the Trust’s Net Profits Interest in the 2023

Divestiture Properties.

On August 9, 2023, the Sponsor completed the sale of the 2023 Divestiture Properties, and the Trustee, on

behalf of the Trust, reconveyed, terminated and released to the Sponsor the Net Profits Interest with respect to the 2023 Divestiture

For additional information regarding this transaction, see “Trustee’s Discussion and Analysis of Financial Condition

and Results of Operations—Sale of 2023 Divestiture Properties”

in Part II, Item 7 of this Form 10-K.

The Net Profits Interest is passive in nature

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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.

collecting cash attributable

to the Net Profits Interest;

paying expenses, charges

and obligations of the Trust from the Trust’s assets;

distributing distributable

cash to the Trust unitholders;

causing to be prepared

and distributed a tax information report for each Trust unitholder and preparing and filing

tax returns on behalf of the Trust;

causing to be prepared

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

(the “Exchange Act”), and by the rules of any securities exchange or quotation

system on which the Trust Units are listed or admitted to trading;

causing to be prepared

and filed a reserve report by or for the Trust by independent reserve engineers as of December 31

of each year in accordance with criteria established by the Securities and Exchange Commission

(the “SEC”);

establishing, evaluating

and maintaining a system of internal control over financial reporting in compliance with

the requirements of the Sarbanes-Oxley Act of 2002;

enforcing the Trust’s

rights under certain agreements;

taking any action it

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

In connection with the formation of the Trust,

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The Trustee may create a cash reserve to pay for

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

that exceed its cash on hand and available reserves.

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

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

lend funds to the Trust.

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

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

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

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

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

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

funds to the Trust necessary to pay such expenses.

future liabilities of the Trust.

In addition, the Trustee may authorize the Trust to borrow money to pay administrative or incidental

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

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

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

thereof intends to lend funds to the Trust.

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

The terms of such indebtedness and security interest, if the Trustee, Delaware Trustee or an affiliate thereof were to loan funds, would

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

relationship.

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

the Trust if the Trust’s cash on hand (including available cash reserves) is not sufficient to pay ordinary course administrative

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

to loan funds to the Trust necessary to pay such expenses.

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

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In November 2021, the Trustee notified COERT

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

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

The cash held by

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

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

of the Trust.

From February 2022 through March 2023, the Trustee withheld $37,833, and commencing with the distribution to

Trust unitholders paid in April 2023 has been withholding and in the future intends to withhold $50,000, from the funds otherwise

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

The Trustee may increase or decrease

the targeted cash reserve amount at any time, and may increase or decrease the rate at which it is withholding funds to build the cash

reserve at any time, without advance notice to the Trust unitholders.

Cash held in reserve will be invested as required by the Trust

Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent

expenses or liabilities eventually will be distributed to Trust unitholders, together with interest earned on the funds.

As of December 31,

2023, this cash reserve totaled $941,386.

Each month, after paying Trust obligations and

expenses, the Trustee distributes to the Trust unitholders any remaining proceeds received from the Net Profits Interest.

The cash held

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

account or may be invested in:

interest-bearing

obligations of the United States government;

market funds that invest only in United States government securities;

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

certificates of deposit.

interest-bearing obligations

of the United States government;

money market funds

that invest only in United States government securities;

repurchase agreements

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

bank certificates of

The Trust is not subject

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will dissolve upon the earliest to occur of the following:

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

the Net Profits Interest;

annual cash proceeds received by the Trust attributable to the Net Profits Interest are less

than $2 million for each of any two consecutive years;

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

Trust is judicially dissolved.

the Trust, upon approval

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

the annual cash proceeds

received by the Trust attributable to the Net Profits Interest are less than $2 million

for each of any two consecutive years;

the holders of at least

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

the Trust is judicially

Upon dissolution of the Trust,

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

downgrade as the Sponsor.

downgrade that the Sponsor receives.

The operators of the Underlying Properties sell

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for the periods presented.

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

Year Ended December 31,

The table provides the percentage represented by each of these purchasers during

the periods presented:

Pioneer Natural

Resources USA

Occidental Petroleum

HollyFrontier

Competition and Markets

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

In the event that the net profits for any computation

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

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

If the net profits for any computation period

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

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

Unless otherwise advised by counsel or the Internal

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The Trust is responsible for all costs associated with calling

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

for all costs associated with calling such meeting.

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

of such meeting.

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

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

Trust unitholders representing a majority of Trust

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

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

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

Unless otherwise required by the Trust Agreement,

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

meeting are responsible for all such costs.

Meetings must be held in such location as the Trustee designates in the notice of such meeting.

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

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

Trust unitholders representing a majority of Trust Units outstanding

must be present or represented by proxy to have a quorum.

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

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

Unless the Trust Agreement otherwise requires,

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

where there is a quorum.

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

The affirmative vote of the holders

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

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

the rights of Trust unitholders in any material respect);

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

At the special meeting of Trust unitholders held

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

In September 2017, Enduro, the Trustee and the

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

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

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

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

This amendment reduced the

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

In addition, certain amendments to the Trust Agreement

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

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

The affirmative vote

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

dissolve the Trust;

amend the Trust Agreement

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

unitholders in any material respect);

approve the sale of

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

In September 2017, following a special meeting

of Trust unitholders at which unitholders approved amendments to the Trust Agreement, Enduro, the Trustee and the Delaware Trustee entered

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

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

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

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

This amendment reduced the required threshold for

approval of such sales from holders of 75% to holders of 50% of the outstanding Trust Units.

In addition, the Trustee may make certain amendments

to the Trust Agreement without approval of the Trust unitholders.

Computation of Net Profits

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Net Profits Interest

The amounts paid to the Trust for the Net Profits

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

The amounts paid to the Trust with respect to

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

and “net profits”

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.

contained in the Conveyance and described below.

Under the Conveyance, net profits are computed monthly, and 80% of the aggregate net

profits attributable to the sale of oil and natural gas production from the Underlying Properties for each calendar month will be paid

to the Trust on or before the end of the following month.

The Sponsor will not pay to the Trust any interest on the net profits held

by the Sponsor prior to payment to the Trust, provided that such payments are timely made.

Gross profits ”

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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,

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;

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

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;

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

all insurance premiums

attributable to the ownership or operation of the Underlying Properties for insurance actually

carried with respect to the Underlying Properties, or any equipment located on any of the

Underlying Properties, or incident to the operation or maintenance of the Underlying Properties;

all amounts and other

consideration for (i) rent and the use of or damage to the surface, (ii) delay

rentals, shut-in well payments, minimum royalties and similar payments and (iii) fees

for renewal, extension, modification, amendment, replacement or supplementation of the leases

included in the Underlying Properties;

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).

all amounts charged

by the relevant operator as overhead, administrative or indirect charges specified in the

applicable operating agreements or other arrangements covering the Underlying Properties

or operations with respect thereto;

to the extent that

the Sponsor is the operator of certain of the Underlying Properties and there is no operating

agreement covering such portion of the Underlying Properties, those overhead, administrative

or indirect charges that are allocated by the Sponsor to such portion of the Underlying Properties;

if, as a result of

the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of

hydrocarbons produced from the Underlying Properties, any amounts previously credited to

the determination of the net profits are reclaimed from the Sponsor, then the amounts reclaimed;

all costs and expenses

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

amounts previously

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

at the option of the

Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved

development expenditure projects, including well drilling, recompletion and workover costs,

which amounts will at no time exceed $2.0 million in the aggregate, and will be subject to

the limitations described below (provided that such costs shall not be debited from gross

profits when actually incurred).

As mentioned above, the costs deducted in the

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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

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

however, if the net profits for any computation period is a negative amount,

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

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

The Trust uses the modified cash basis of accounting

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

This comprehensive basis of accounting other

than GAAP corresponds to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E,

Financial Statements of Royalty Trusts.

The Net Profits Interest represents the right to receive revenues (oil and natural gas

sales), less direct operating expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying

Properties, multiplied by 80%.

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

to terms of the Conveyance.

to report Trust receipts of net profits and payments of expenses incurred.

This comprehensive basis of accounting other than GAAP corresponds

to the accounting permitted for royalty trusts by the SEC as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements

of Royalty Trusts.

The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating

expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied

Cash distributions of the Trust will be made based on the amount of cash received by the Trust with respect to the corresponding

production month pursuant to terms of the Conveyance.

Additional Provisions

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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.

any proceeds that are

withheld for any reason (other than at the request of the Sponsor) are not considered received

until such time that the proceeds are actually collected;

amounts received and

promptly deposited with a non-affiliated escrow agent will not be considered to have been

received until disbursed to the Sponsor by the escrow agent;

amounts received and

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

The Trustee is not obligated to return any cash

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In addition, the Sponsor may, without the consent

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

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

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

These releases

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

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

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).

of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with any lease that accounts for no more

than 0.25% of the total production from the Underlying Properties in the prior 12 months, provided that the Net Profits Interest covered

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

These releases will

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

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

In May 2023, the Sponsor sold approximately $0.3 million in non-producing, non-cash flowing acreage to a private oil company, free

and clear of the Net Profits Interest, as permitted under the Trust Agreement.

The proceeds from this sale attributable to the Trust’s

Net Profits Interest were included in the distribution that was paid to Trust unitholders on August 14, 2023.

As the designated operator of a property included

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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.

to determine the amounts payable to the Trust with respect to the Net Profits Interest.

Monthly and annually, the Sponsor must deliver

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

The Trustee has the right to inspect and

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

The Sponsor has further

agreed to provide the Trust and Trustee with all information and services as are reasonably necessary to fulfill the purposes of the

Trust, including such accounting, bookkeeping and informational services as may be necessary for the preparation of reports the Trust

is required to prepare or file in accordance with applicable tax and securities laws, exchange listing rules and other requirements,

including reserve reports and tax returns.

Following the sale of all or any portion of the Underlying Properties, the purchaser will

be bound by the obligations of the Sponsor under the Trust Agreement and the Conveyance with respect to the portion sold.

Federal Income Tax Matters

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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.

obtain permits to conduct

regulated activities;

limit or prohibit

drilling activities on certain lands lying within wilderness, wetlands and other protected

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

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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”

The Comprehensive Environmental Response, Compensation and Liability Act, as amended (“CERCLA”),

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

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

into the environment.

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

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

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.

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

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

Although the Sponsor and, as applicable,

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

time, hydrocarbons and wastes may have been disposed of or released at or from the real properties upon which the Sponsor conducts its

operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes have been taken for treatment or disposal.

In addition, the properties upon which the Sponsor conducts its operations may have been operated by third parties or by previous owners

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

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

Under these laws, the Sponsor could

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

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

Environmental Protection Agency (“EPA”)

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

the responsible classes of persons the costs they incur.

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

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

Although petroleum,

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

under CERCLA, the Sponsor

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

exclusion.”

The Sponsor also generates solid and hazardous

wastes that are subject to the requirements of the Resource Conservation and Recovery Act, as amended (“RCRA”), and comparable

state statutes.

RCRA imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes.

In the course of its operations, The Sponsor generates petroleum hydrocarbon wastes and ordinary industrial wastes that may be classified

as hazardous wastes under RCRA and comparable state laws.

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

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

While many exploration and production wastes are exempt from regulation as hazardous waste, these wastes are generally subject to non-hazardous

waste regulation under RCRA and applicable state regulations.

Many state governments have specific regulations and guidance for exploration

and production wastes, including the wastes associated with hydraulic fracturing activities.

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

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

that were standard in the industry at the time, hydrocarbons and wastes may have been disposed of or released at or from the real properties

upon which the Sponsor conducts its operations, or at or from other, offsite locations, where these petroleum hydrocarbons and wastes

have been taken for treatment or disposal.

In addition, the properties upon which the Sponsor conducts its operations may have been operated

by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or hydrocarbons was

not under the Sponsor’s control.

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

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.

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.

on the discharge of pollutants into “waters of the United States”

and waters within the scope of the state law, respectively.

Pursuant to the CWA and applicable state laws, permits must be obtained to discharge pollutants into regulated waters.

Any such discharge

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

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

state agency or both.

The discharge of wastewater from most onshore oil and gas exploration and production activities is currently prohibited

east of the 98 th meridian.

Additionally, in June 2016, the EPA issued a final rule implementing wastewater pretreatment

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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.

CWA Section 401 provides that the applicant for a Section 404 USACE permit for

the discharge of dredge and fill materials must seek a Section 401 water quality certification by applying to the state in which

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

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

How the EPA and the USACE define “waters

2 unchanged sentences

Sponsor’s regulatory and permitting obligations under the CWA.

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

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

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

1 unchanged sentence

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

Shortly thereafter, the Supreme Court issued its decision

in Sackett II which overturned a substantial portion of the basis for the 2023 Rule.

USACE and the EPA subsequently amended the 2023

rule and excluded a number of types of wetlands and streams from CWA jurisdiction, but the rule is subject to litigation regarding

the sufficiency of the agencies’

interpretation of the Sackett II decision.

The Sponsor’s regulatory obligations and permitting

costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of CWA regulation, given the

ongoing litigation.

USACE Nationwide Permits (“NWPs”)

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

wetlands or other waters of the United States under the CWA 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

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.

wetlands or other waters of the United States under the CWA.

Some NWPs are also used to authorize activities that impact traditional

navigable waters under the Rivers and Harbors Act.

The current administration has stated an intention to re-visit NWP 12, which

is used to authorize regulated impacts related to construction of oil and gas pipelines, through notice and comment rulemaking before

its current expiration date of February 2026.

In addition, a federal court in Washington, D.C.

is currently hearing a challenge

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

may restrict or remove the ability to use NWP

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

This could result in additional

cost and time for permitting projects.

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

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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

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

emission of air pollutants from many sources and also impose various monitoring and reporting requirements.

6 unchanged sentences

for oil and gas sources under the CAA.

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

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

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

completions.”

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

reciprocating compressors, and from pneumatic controllers and storage vessels.

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

In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that

require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells

for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as

“green completions.”

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

seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks.

These NSPS apply

to sources that are newly constructed or modified after the rules’

applicability dates.

More recently, in December 2023 the

EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed

or modified after December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps,

storage vessels, process controllers, well completions and liquids unloading, and equipment leaks.

Additionally, the EPA for the first

time adopted emissions guidelines that will apply to existing oil and gas sources and that require reductions in volatile organic compound

and methane emissions that are largely equivalent to the requirements for new sources.

The existing source emissions guidelines are to

be implemented through state plans, with expected compliance dates for existing sources arriving in 2029.

The EPA is also charged with establishing National

4 unchanged sentences

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.

More recently, however, in February 2024, the EPA announced a final rule that will lower the annual standard for

fine particulate matter from 12 micrograms per cubic meter to 9 micrograms per cubic meter.

State or federal implementation of the NAAQS could

result in stricter permitting or regulatory requirements, delay or prohibit the Sponsor’s ability to obtain such permits, and result

in increased expenditures for pollution control equipment.

Although the Sponsor may be required to incur certain capital expenditures

during the next few years for air pollution control equipment or other air emissions-related issues, at this time the Sponsor does not

expect that such requirements will have a material adverse effect on its operations.

In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”)

3 unchanged sentences

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

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

These new sources include gathering and boosting facilities.

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

In addition, in June 2016

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

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

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

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.

In a separate executive order issued on January 20,

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

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

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

national monuments and refuges.

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

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

“social cost of nitrous oxide”

and “social cost of methane,”

which are “the monetized damages associated

with incremental 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.”

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.

reconstructed oil and gas sources—as well as the EPA’s recently adopted methane emissions guidelines for existing oil and

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.

the EPA has recently proposed rules to implement the mandatory Waste Emissions Charge set forth in the Inflation Reduction Act of

2022 (the “IRA”), which will charge a fee based on the methane emissions from applicable facilities in the oil and gas sector

starting in 2024.

The EPA has established pollution control standards

for oil and gas sources under the CAA.

In 2012 and 2016, the EPA adopted federal New Source Performance Standards (“NSPS”) that

require the reduction of volatile organic compound and sulfur dioxide emissions from certain fractured and refractured natural gas wells

for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as

“green completions.”

These regulations also establish specific requirements limiting emissions from production-related wet

seal and reciprocating compressors, pumps, and from pneumatic controllers and storage vessels, and for equipment leaks.

These NSPS apply

to sources that are newly constructed or modified after the rules’

applicability dates.

More recently, in December 2023 the

EPA adopted a final rule that will directly regulate volatile organic compound and methane emissions from new oil and gas sources

and will require further reductions in emissions through its regulation of flaring, compressors, pumps, storage vessels, process controllers,

well completions and liquids unloading, and equipment leaks.

At the same time, the EPA adopted emissions guidelines that will apply to

existing oil and gas sources and that require reductions in volatile organic compound and methane emissions that are largely equivalent

to the requirements for new sources.

The existing source emissions guidelines are to be implemented through state plans, with expected

compliance dates for existing sources arriving in 2029.

The IRA included new Clean Air Act section 136(c) directing

the EPA to collect the Waste Emissions Charge from facilities in the oil and gas sector that report more than 25,000 tons of carbon dioxide

equivalent emissions in a calendar year.

The charge will first apply to methane emissions from calendar year 2024.

The charge is determined

by comparing actual reported methane emissions to statutorily established “methane intensity figures”

that are based on gas

production or throughput, with a charge assessed for every ton of methane emissions that exceeds the facility’s allowable emissions

based on the applicable methane intensity figure.

The charge will be $900 per ton for 2024 emissions, and will increase to $1,200 and

then $1,500 per ton in subsequent years.

The program includes key exemptions, most notably a regulatory compliance exemption that applies

to and exempts the emissions from facilities that are subject to and in complete compliance with EPA’s new or existing source methane

requirements.

The EPA proposed new rules to implement the Waste Emissions Charge program in January 2024.

Additionally, more than one-third of the states

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

and/or regional GHG cap and trade programs.

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

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

limitations or allowance purchase requirements in the future.

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

to reduce emissions of greenhouse gases.

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

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

The adoption and implementation of regulations

26 unchanged sentences

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.

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.

In 2023, the Biden Administration issued a second proposed rule that would make significant changes to the Trump Administration

The proposed rule is expected to be finalized in April 2024.

In addition, in early 2023 the White House Council

on Environmental Quality issued Guidance to the federal agencies on how agencies should consider greenhouse gas emissions and climate

impacts in the course of their reviews under NEPA.

Although the Trump Administration regulations were never fully implemented, the Biden

Administration changes may have a meaningful impact on federal reviews related to the Sponsor, especially as those reviews relate to

climate and environmental justice.

The federal Endangered Species Act, as amended (“ESA”), prohibits take of listed endangered, and

in some cases threatened, species.

Under the ESA, federal agencies are obligated to consult with the U.S.

Fish and Wildlife Service

or National Marine Fisheries Service if an agency’s actions, including permit actions, may affect listed species or designated

critical habitat.

If endangered species are located in areas of the Underlying Properties where seismic surveys, development activities

or abandonment operations may be conducted, the work could be prohibited or delayed or expensive mitigation may be required, depending

on the implications for protected species and designated critical habitat.

On August 27, 2019, the U.S.

Fish and Wildlife Service published a final rule adopting several

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

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

In January 2021, President

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

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

has 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.

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

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

of the 2019 amendments to the ESA rules.

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

dealing with critical habitat, and has issued a proposed rule that would make significant changes to the federal consultation process.

That rule is expected to be finalized by the Biden Administration.

Changes to these rules could make a federal review process

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

In addition, designation of new species as threatened

or endangered could cause the Sponsor to incur additional costs arising from species protection measures, could result in limitations

on activities, and could require a more complex regulatory compliance process.

health and safety.

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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