What changed in this filing

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Item 1. Business

2025-03-19 compared with 2024-03-22 · 519 added, 555 removed, 491 unchanged (69% of the section changed)

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Trustee”), as Delaware Trustee.

The Trust was created to acquire and hold for

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

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

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

The properties in which the Trust

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

In connection with the closing of the initial

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

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

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

The Trust was created to acquire and hold for the

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

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

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

The properties in which the Trust holds

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

In connection with the closing of the initial public

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

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

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

By virtue of the merger, Enduro Texas retained all rights, title and interest to the Net Profits Interest.

Enduro Operating and

Enduro Texas entered into a Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (as supplemented and amended

to date, the “Conveyance”), to effect the transfer of the Net Profits Interest from Enduro Operating to Enduro Texas.

On November 8, 2011, Enduro Texas merged

with and into the Trust (the “Trust Merger”) pursuant to an Agreement and Plan of Merger dated November 3, 2011 (the

“Trust Merger Agreement”).

Under the terms of the Trust Merger Agreement, the Trust continued as the surviving entity, and

the limited liability company interest in Enduro Texas held by Enduro prior to the effective time of the Trust Merger converted into

the right to receive 33,000,000 Trust Units.

Further, by virtue of the Trust Merger, the Trust retained all right, title and interest

to the Net Profits Interest (including the right to enforce the Conveyance against Enduro Operating, as grantor).

On November 8,

2011, the Trust, Enduro Operating and Enduro Texas entered into a Supplement to Conveyance of Net Profits Interest to acknowledge that

The Bank of New York Mellon Trust Company, N.A., as Trustee, is deemed the grantee under the Conveyance and a party thereto.

Enduro Operating and Enduro

Texas entered into a Conveyance of Net Profits Interest, dated effective as of July 1, 2011 (as supplemented and amended to date,

the “Conveyance”), to effect the transfer of the Net Profits Interest from Enduro Operating to Enduro Texas.

On November 8, 2011, Enduro Texas merged with

and into the Trust (the “Trust Merger”) pursuant to an Agreement and Plan of Merger dated November 3, 2011 (the “Trust

Merger Agreement”).

Under the terms of the Trust Merger Agreement, the Trust continued as the surviving entity, and the limited

liability company interest in Enduro Texas held by Enduro prior to the effective time of the Trust Merger converted into the right to

receive 33,000,000 Trust Units.

Further, by virtue of the Trust Merger, the Trust retained all right, title and interest to the Net Profits

Interest (including the right to enforce the Conveyance against Enduro Operating, as grantor).

On November 8, 2011, the Trust, Enduro

Operating and Enduro Texas entered into a Supplement to Conveyance of Net Profits Interest to acknowledge that The Bank of New York Mellon

Trust Company, N.A., as Trustee, is deemed the grantee under the Conveyance and a party thereto.

Immediately following the Trust Merger, Enduro

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In September 2017,

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

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

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

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

This amendment reduced the required threshold for approval

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

To effect the same changes as those included in the

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

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”).

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

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

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

held in accordance with the requirements of the Trust Agreement.

This amendment reduced the required threshold for approval of such sales

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

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

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

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

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

“Partial Release”).

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

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

On August 31, 2018, COERT Holdings 1 LLC

(“COERT”

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

Enduro (the “Sale Transaction”).

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

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

COERT is a Delaware limited liability company

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

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

On May 3, 2023, the Sponsor notified the

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

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

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

On 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

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

The Net Profits Interest is passive in nature

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

The Net Profits Interest is passive in nature and

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

The Net Profits Interest entitles the Trust to receive 80% of the net profits from the sale of oil and natural gas production

from the Underlying Properties during the term of the Trust.

The Trust Agreement provides that the Trust’s business activities

are limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or

permitted by the terms of the Conveyance.

As a result, the Trust is not permitted to acquire other oil and natural gas properties or

net profits interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits

The Trust Agreement provides that the Trust’s business activities are

limited to owning the Net Profits Interest and any activity reasonably related to such ownership, including activities required or permitted

by the terms of the Conveyance.

As a result, the Trust is not permitted to acquire other oil and natural gas properties or net profits

interests or otherwise to engage in activities beyond those necessary for the conservation and protection of the Net Profits Interest.

Trust has no employees.

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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.

· 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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Conveyance and the Registration Rights Agreement without the approval of Trust unitholders in order to cure any ambiguity, to correct

or supplement any defective or inconsistent provisions, to grant any benefit to all of the Trust unitholders, to comply with changes

in applicable law or to change the name of the Trust.

Such supplement or amendment, however, may not materially adversely affect the

interests of the Trust unitholders.

or supplement any defective or inconsistent provisions, to grant any benefit to all of the Trust unitholders, to comply with changes in

applicable law or to change the name of the Trust.

Such supplement or amendment, however, may not materially adversely affect the interests

of the Trust unitholders.

The Trustee may create a cash reserve to pay for

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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.

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

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

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

The Trustee may increase or decrease the

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

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

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

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

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

As of December 31,

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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

The Trust is not subject

to any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time.

will dissolve upon the earliest to occur of the following:

the Trust, upon approval

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

the annual cash proceeds

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

for each of any two consecutive years;

the holders of at least

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

the Trust is judicially

· 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 deposit.

The Trust is not subject to

any pre-set termination provisions based on a maximum volume of oil or natural gas to be produced or the passage of time.

The Trust will

dissolve upon the earliest to occur of the following:

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

· the annual cash proceeds received by the Trust attributable to the Net Profits Interest are less than $2 million for each of

any two consecutive years;

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

· the Trust is judicially dissolved.

Upon dissolution of the Trust,

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The price received by the operators for the

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

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

Natural gas produced by the operators is

marketed and sold to third-party purchasers.

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

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

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

adjustments for Btu content, transportation and related charges.

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

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

Natural gas produced by the operators is marketed

and sold to third-party purchasers.

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

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

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

for Btu content, transportation and related charges.

The following purchasers individually accounted

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the periods presented:

Pioneer Natural

Resources USA

Occidental Petroleum

Year Ended December 31,

Pioneer Natural Resources USA

Holly Frontier

Competition and Markets

The oil and natural gas industry is highly competitive.

The Sponsor competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas,

equipment, personnel and markets for the sale of oil and natural gas.

Many of these competitors are financially stronger than the Sponsor,

but even financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt

to maintain cash flow.

Because the Sponsor and the third-party operators of the Underlying Properties are subject to competitive conditions

in the oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.

The Sponsor competes with major oil and natural gas companies and independent oil and natural gas companies for oil and natural gas, equipment,

personnel and markets for the sale of oil and natural gas.

Many of these competitors are financially stronger than the Sponsor, but even

financially troubled competitors can affect the market because of their need to sell oil and natural gas at any price to attempt to maintain

Because the Sponsor and the third-party operators of the Underlying Properties are subject to competitive conditions in the

oil and natural gas industry, the Trust’s Net Profits Interest is indirectly subject to those same competitive conditions.

Oil and natural gas compete with other forms of

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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.

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

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

If the net profits for any computation period is a negative

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

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

Unless otherwise advised by counsel or the Internal

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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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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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· 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).

· 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

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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

The amounts paid to the Trust with respect to

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”

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.

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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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 Properties;

all amounts and other

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

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

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

included in the Underlying Properties;

all amounts charged

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

applicable operating agreements or other arrangements covering the Underlying Properties

or operations with respect thereto;

to the extent that

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

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

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

if, as a result of

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

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

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

all costs and expenses

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

amounts previously

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

at the option of the

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

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

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

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

profits when actually incurred).

As mentioned above, the costs deducted in the

net profits determination will be reduced by certain offset amounts.

The offset amounts are further described in the Conveyance, and

include, among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying

Properties and certain non-production revenues, including salvage value for equipment related to plugged and abandoned wells.

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):

· with the exception of certain costs and expenses related to 20 wells located in the Haynesville Shale identified in the Conveyance,

all costs for (i) drilling, development, production and abandonment operations, (ii) all direct labor and other services necessary

for drilling, operating, producing and maintaining the Underlying Properties and workovers of any wells located on the Underlying Properties,

(iii) treatment, dehydration, compression, separation and transportation, (iv) all materials purchased for use on, or in connection

with, any of the Underlying Properties and (v) any other operations with respect to the exploration, development or operation of

hydrocarbons from the Underlying Properties;

· all losses, costs, expenses, liabilities and damages with respect to the operation or maintenance of the Underlying Properties for

(i) defending, prosecuting, handling, investigating or settling litigation, administrative proceedings, claims, damages, judgments,

fines, penalties and other liabilities, (ii) the payment of certain judgments, penalties and other liabilities, (iii) the payment

or restitution of any proceeds of hydrocarbons from the Underlying Properties, (iv) complying with applicable local, state and federal

statutes, ordinance, rules and regulations, (v) tax or royalty audits and (vi) any other loss, cost, expense, liability

or damage with respect to the Underlying Properties not paid or reimbursed under insurance;

· all taxes, charges and assessments (excluding federal and state income, transfer, mortgage, inheritance, estate, franchise and like

taxes) with respect to the ownership of, or production of hydrocarbons from, the Underlying Properties;

· all insurance premiums attributable to the ownership or operation of the Underlying Properties for insurance actually carried with

respect to the Underlying Properties, or any equipment located on any of the Underlying Properties, or incident to the operation or maintenance

of the Underlying Properties;

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

payments, minimum royalties and similar payments and (iii) fees for renewal, extension, modification, amendment, replacement or supplementation

of the leases included in the Underlying Properties;

· all amounts charged by the relevant operator as overhead, administrative or indirect charges specified in the applicable operating

agreements or other arrangements covering the Underlying Properties or operations with respect thereto;

· to the extent that the Sponsor is the operator of certain of the Underlying Properties and there is no operating agreement covering

such portion of the Underlying Properties, those overhead, administrative or indirect charges that are allocated by the Sponsor to such

portion of the Underlying Properties;

· if, as a result of the occurrence of the bankruptcy or insolvency or similar occurrence of any purchaser of hydrocarbons produced

from the Underlying Properties, any amounts previously credited to the determination of the net profits are reclaimed from the Sponsor,

then the amounts reclaimed;

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

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

· at the option of the Sponsor (or any subsequent owner of the Underlying Properties), amounts reserved for approved development expenditure

projects, including well drilling, recompletion and workover costs, which amounts will at no time exceed $2.0 million in the aggregate,

and will be subject to the limitations described below (provided that such costs shall not be debited from gross profits when actually

As mentioned above, the costs deducted in the net

profits determination will be reduced by certain offset amounts.

The offset amounts are further described in the Conveyance, and include,

among other things, certain net proceeds attributable to the treatment or processing of hydrocarbons produced from the Underlying Properties

and certain non-production revenues, including salvage value for equipment related to plugged and abandoned wells.

If the offset amounts

exceed the costs during a monthly period, the ability to use such excess amounts to offset costs will be deferred and utilized as offsets

in the next monthly period to the extent such amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable

month, are less than the costs arising in such month.

The Trust is not liable to the owners of the Underlying

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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:

· 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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(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.

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

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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.

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.

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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

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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.

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.

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(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.

likely will take the position that a unitholder must recapture depletion upon the disposition of a unit.

The IRS likely will

take the position that a unitholder must recapture depletion upon the disposition of a unit.

Classification of the Net Profits Interest

Tax counsel to the Trust advised the Trust at

the time of formation that, for U.S.

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

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

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

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

mineral interests they burden.

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

Interest should be treated differently.

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

loss in respect of an investment in Trust Units.

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”).

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”).

Therefore, the Trustee

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

federal income tax purposes.

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

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

requirements of the Trust as a WHFIT.

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

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

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

Unitholders whose Trust

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

with respect to the Trust Units.

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

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

Available Trust Tax Information

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.

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

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.

These laws and regulations may impose

significant obligations on the Sponsor’s operations, including requirements to:

· obtain permits to conduct regulated activities;

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

· restrict the types, quantities and concentration of materials that can be released into the environment in the performance of drilling,

completion and production activities;

· initiate investigatory and remedial measures to mitigate pollution from former or current operations, such as restoration of drilling

pits and plugging of abandoned wells;

· apply specific health and safety criteria addressing worker protection.

Failure to comply with environmental laws and regulations

may result in the assessment of significant administrative, civil and criminal sanctions, including monetary penalties, the imposition

of joint and several liability, investigatory and remedial obligations, and the issuance of injunctions limiting or prohibiting some or

all of the Sponsor’s operations.

Moreover, these laws, rules and regulations may restrict the rate of oil and natural gas production

below the rate that would otherwise be possible.

The regulatory burden on the oil and natural gas industry increases the cost of doing

business in the industry and consequently affects profitability.

The Sponsor has advised the Trustee that it believes that it is in substantial

compliance with all existing environmental laws and regulations applicable to its current operations and that its continued compliance

with existing requirements will not have a material adverse effect on the cash distributions to the Trust unitholders.

Although the Trump

Administration had taken steps aimed at reducing federal regulatory burdens and costs for oil and natural gas production operations, the

recent trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment,

and thus, any changes in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent

and costly construction, drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation

obligations could have a material adverse effect on the Sponsor’s development expenses, results of operations and financial position.

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

Moreover, accidental releases or spills may

occur in the course of the Sponsor’s operations, and there can be no assurance that the Sponsor will not incur significant costs

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

Moreover, accidental releases or spills may occur in the course

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

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

The following is a summary of certain existing

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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

under CERCLA, the Sponsor handles

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

exclusion.”

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the 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

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.

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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

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

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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.

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.

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

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Any such discharge

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

state agency or both.

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

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

standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending certain wastewater directly to

publicly owned treatment works (“POTW”).

Unconventional extraction facilities are allowed by 40 CFR Part 437 to send

wastewater to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances.

CWT facilities

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

In 2018, the EPA concluded a study of the treatment

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

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

Any restriction of disposal

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

standards that prohibit onshore unconventional oil and natural gas extraction facilities from sending certain wastewater directly to publicly

owned treatment works (“POTW”).

Unconventional extraction facilities are allowed by 40 CFR Part 437 to send wastewater

to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances.

CWT facilities can either

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

In 2018, the EPA concluded a study of the treatment and discharge

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

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

Any restriction of disposal options for hydraulic

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

The discharge of dredge and fill material in waters

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of the United States”

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

Sponsor’s regulatory and permitting obligations under the CWA.

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

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

Supreme Court

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

Shortly thereafter, the Supreme Court issued its decision

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

USACE and the EPA subsequently amended the 2023

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

the sufficiency of the agencies’

(“WOTUS”), which defines the extent of geographic jurisdiction under the CWA, can impact the Sponsor’s

regulatory and permitting obligations under the CWA.

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

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

Supreme Court decisions and

guidance issued by the EPA and USACE interpreting the decisions.

Shortly thereafter, the Supreme Court issued its decision in Sackett

II which overturned a substantial portion of the basis for the 2023 rule.

The USACE and the EPA subsequently amended the 2023 rule and

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

of the agencies’

interpretation of the Sackett II decision.

The Sponsor’s regulatory obligations and permitting

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

ongoing litigation.

USACE Nationwide Permits (“NWPs”)

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

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

Some NWPs are also used to authorize activities that impact traditional

navigable waters under the Rivers and Harbors Act.

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

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

its current expiration date of February 2026.

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

is currently hearing a challenge

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 2023 rule is presently in effect in about half of the states

while it is enjoined in the other half.

In those states where the rule is enjoined, the EPA and the USACE define WOTUS in accordance

with an earlier regulatory definition adjusted in light of the Supreme Court’s Sackett II decision.

The Sponsor’s regulatory

obligations and permitting costs will continue to be subject to remaining uncertainty around the definition of WOTUS and the scope of

CWA regulation, given the ongoing litigation.

USACE Nationwide Permits (“NWPs”) are

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

or other waters of the United States under the CWA.

Some NWPs are also used to authorize activities that impact traditional navigable

waters under the Rivers and Harbors Act.

NWP 12 will expire in March 2026 and be replaced with a new version.

a federal court in Washington, D.C.

is currently hearing a challenge to NWP 12.

An adverse decision in the litigation 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.

In February 2025, the USACE began implementing

emergency permitting procedures as directed by President Trump’s Executive Order Declaring a National Energy Emergency.

result in substantially decreased timeframes for receiving Section 404 permits in the case of energy projects subject to the Executive

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

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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.

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

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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.

While the U.S.

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.

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.

To date, the EPA has taken no further action in response to

the December 2016 report.

However, in April 2024, the BLM issued a final rule to reduce the waste of natural gas from venting,

flaring, and leaks during oil and gas production activities on federal and American Indian leases.

On August 16, 2012 the EPA published final

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on all hydraulically fractured gas wells constructed or refractured after January 1, 2015.

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.

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

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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.

Further, some local governments have imposed moratoria on drilling permits within city limits so

that local ordinances may be reviewed to assess their adequacy to address such activities.

Similar measures could be considered or implemented

in the jurisdictions in which the Underlying Properties are located.

However, in May 2015, the Texas legislature enacted a bill preempting

local bans on hydraulic fracturing.

Meanwhile, in Texas, specific oil and natural gas regulations apply to oil and gas operations,

including the drilling, completion and operations of wells, and the disposal of waste oil and salt water.

In October 2023, the Texas

Railroad Commission (“RRC”) announced draft amendments to its water protection rules to, among other things, encourage

waste recycling.

There are also procedures incident to the plugging and abandonment of dry holes or other non-operational wells, all as

governed by the applicable governing state agency.

As an example, the RRC adopted rules in 2014 requiring companies seeking permits

for disposal wells to provide seismic activity data in permit applications.

The rules also allow the RRC to modify, suspend, or terminate

permits if a disposal well is determined to be causing seismic activity.

Determinations by the RRC under these rules may adversely

affect our operations.

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

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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.

More recently, the EPA adopted a final rule in

2024 that will directly regulate volatile organic compound and methane emissions from oil and gas sources constructed or modified after

December 2022 and will require reductions in both pollutants through its regulation of flaring, compressors, pumps, storage vessels,

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

Additionally, the EPA for the first time adopted emissions

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

that are largely equivalent to the requirements for new sources.

The existing source emissions guidelines are to be implemented through

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

The EPA is also charged with establishing National

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

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”)

may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse

gases under existing provisions of the CAA.

These regulations include limits on tailpipe emissions from motor vehicles, preconstruction

and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and

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

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

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.

The 2024 presidential election in the United States

may impact the air quality-related requirements that apply to the Sponsor.

The Trump Administration may adopt a different approach to

many actions taken under the prior presidential administration, including the 2024 revisions to the emissions standards and guidelines

for new and existing sources in the oil and gas industry, as well as the 2024 changes to the NAAQS for fine particulate matter.

of the Trump Administration’s evaluation of the prior administration’s regulatory approach is not certain at this time, but

President Trump has made it clear that his energy agenda prioritizes an increase in domestic oil and gas production.

The Sponsor may be required to incur certain capital

expenditures for air pollution control equipment or other air emissions-related issues, The Sponsor currently does not expect that such

requirements will have a material adverse effect on its operations.

In response to its 2009 finding that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”)

may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse gases

under existing provisions of the CAA.

These regulations include limits on tailpipe emissions from motor vehicles, preconstruction and

operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified and reconstructed

oil and gas sources—as well as the EPA’s methane emissions guidelines for existing oil and gas sources that were adopted in

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.

On January 20, 2025,

President Trump announced the withdrawal of the United States from the Paris Climate Agreement.

President Trump also issued an executive

order directing the EPA to review the legality and continuing applicability of its 2009 GHG endangerment finding.

The outcome of that

review is not currently known;

however, it has the potential to eliminate the basis for the EPA’s regulation of GHGs under the CAA.

The EPA has established GHG standards for oil and

gas sources based on the GHG endangerment finding.

In 2024, the EPA adopted a final rule that will directly regulate volatile organic

compound and methane emissions from new oil and gas sources and will require reductions in GHG and volatile organic compound emissions

through its regulation of flaring, compressors, pumps, storage vessels, process controllers, well completions and liquids unloading, and

equipment leaks.

At the same time, the EPA adopted emissions guidelines that will apply to existing oil and gas sources and that require

reductions in volatile organic compound and methane emissions that are largely equivalent to the requirements for new sources.

source emissions guidelines are to be implemented through state plans, with expected compliance dates for existing sources arriving in

The Inflation Reduction Act of 2022 (the “IRA”)

included new Clean Air Act section 136(c) directing the EPA to collect the Waste Emissions Charge (“WEC”) from facilities

in the oil and gas sector that report more than 25,000 tons of carbon dioxide equivalent emissions in a calendar year.

The charge will

first apply to methane emissions from calendar year 2024.

The charge is determined by comparing actual reported methane emissions to statutorily

established “methane intensity figures”

that are based on gas production or throughput, with a charge assessed for every ton

of methane emissions that exceeds the facility’s allowable emissions based on the applicable methane intensity figure.

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 adopted new rules to implement

the WEC program in November 2024;

however, the fate of the WEC and the EPA rules implementing the WEC is unclear.

In February 2025,

the United States House of Representatives and Senate both passed resolutions to repeal the EPA’s 2024 WEC rules under the

Congressional Review Act (“CRA”), and on March 14, 2025 President Trump signed the resolution repealing those rules under the CRA.

the United States House of Representatives and Senate may be considering amendment or repeal of certain portions of the IRA, including

the statutory provisions establishing the WEC.

In addition to the federal actions, more than one-third

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

inventories and/or regional GHG cap and trade programs.

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

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

limitations or allowance purchase requirements in the future.

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

For example, the states of Colorado and New Mexico have adopted rules regulating

GHGs from the oil and gas industry that are based on the federal standards.

Congress may in the future consider adopting other legislation

to reduce emissions of greenhouse gases.

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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.

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.

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

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

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

The Biden Administration undertook an initial revision to the

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

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

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.

2025, agencies undertook NEPA reviews pursuant to binding regulations issued by the White House Council on Environmental Quality (“CEQ”)

as well as pursuant to the federal agency’s own NEPA procedures.

CEQ issued its rules after being directed to do so by an Executive

Order issued in the Carter Administration.

After two federal courts held that CEQ did not have authority to issue binding regulations,

the Trump Administration revoked the Carter Administration Executive Order and directed CEQ to withdraw the regulations.

In their place,

agencies are directed to develop procedures that hew to the statutory text over the course of 2025 with the goal of having them finalized

in early 2026.

In the meantime, agencies will continue to use their own NEPA procedures and may continue to follow the CEQ regulations,

using them as guidance.

This may result in delays and uncertainty in permitting reviews as agencies adjust to a new NEPA approach.

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.

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

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

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.

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.

The Biden Administration

rescinded one of the rules adopted by the prior administration, dealing with critical habitat, and issued a revised rule making

changes to the federal consultation process.

These changes could make a federal review process occasioned by the application for permits,

rights of way, or leases more complex in certain circumstances.

In addition, designation of new species as threatened or endangered could

cause the Sponsor to incur additional costs arising from species protection measures, could result in limitations on activities, and could

require a more complex regulatory compliance process.

In January 2025, the Trump Administration directed the use of the emergency

consultation procedures for permitting for energy projects in the Declaring a National Energy Emergency Executive Order.

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