PART
I
Permianville
Royalty Trust (the “Trust”), previously known as Enduro Royalty Trust, is a Delaware statutory trust formed in May
2011 pursuant to a trust agreement (the “Trust Agreement”) among Enduro Resource Partners LLC (“Enduro”),
as trustor, The Bank of New York Mellon Trust Company, N.A. (the “Trustee”), as trustee, and Wilmington Trust Company
(the “Delaware Trustee”), as Delaware Trustee.
The
Trust was created to acquire and hold for the benefit of the Trust unitholders a net profits interest representing the right to
receive 80% of the net profits from the sale of oil and natural gas production from certain properties in the states of Texas,
Louisiana and New Mexico held by Enduro as of the date of the conveyance of the net profits interest to the Trust (the “Net
Profits Interest”). The properties in which the Trust holds the Net Profits Interest are referred to as the “Underlying
Properties.”
In
connection with the closing of the initial public offering of units of beneficial interest in the Trust (“Trust Units”)
in November 2011, Enduro Operating LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro
Operating”), and Enduro Texas LLC, a Texas limited liability company and a wholly owned subsidiary of Enduro (“Enduro
Texas”), merged, with each entity surviving the 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.
Immediately
following the Trust Merger, Enduro completed an initial public offering of 13,200,000 Trust Units at a price to the public of
$22 per unit.
In
October 2013, Enduro completed a secondary offering of 11,200,000 Trust Units at a price to the public of $13.85 per unit. The
Trust did not sell any Trust Units in the offering and did not receive any proceeds from the offering. After the completion of
the secondary offering, Enduro owned 8,600,000 Trust Units, or 26% of the issued and outstanding Trust Units.
At
a special meeting of Trust unitholders held on August 30, 2017, unitholders approved several proposals, including amendments to
the Trust Agreement and Conveyance. In September 2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment
to Amended and Restated Trust Agreement, which amended certain provisions of the Trust Agreement to, among other things, allow
Enduro to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust unitholders
holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements of the Trust
Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding units of
the Trust. To effect the same changes as those included in the amended Trust Agreement, Enduro, the Trustee and the Delaware Trustee
also entered into the First Amendment to Conveyance of Net Profits Interest. As a result of the Trust unitholders approving amendments
to the Trust Agreement and Conveyance and the approval of the divestiture of certain properties in the Permian Basin, Enduro and
the Trustee entered into the Partial Release, Reconveyance and Termination Agreement (the “Partial Release”). Pursuant
to the terms of the Partial Release, the Trustee, on behalf of the Trust, reconveyed, terminated and released to Enduro the Net
Profits Interest with respect to certain of the Underlying Properties sold pursuant to eight letter agreements or purchase and
sale agreements, as applicable, entered into between Enduro and eight separate counterparties.
In
July 2018, Enduro entered into a purchase and sale agreement with COERT Holdings 1 LLC (“COERT” or the “Sponsor”)
for the Underlying Properties and all of the outstanding Trust Units owned by Enduro (the “Sale Transaction”), and
on August 31, 2018, the parties closed the Sale Transaction. In connection with the Sale Transaction, COERT assumed all of Enduro’s
obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were parties. COERT is a Delaware
limited liability company engaged in the production and development of oil and natural gas from properties located in the Rockies,
the Permian Basin of west Texas and southeastern New Mexico, and the Arklatex region of Texas and Louisiana.
References
to “COERT” or the “Sponsor” in this Form 10-K refer to COERT Holdings 1 LLC, the current sponsor of the
Trust, and references to “Enduro” in this Form 10-K refer to Enduro Resource Partners LLC, the original sponsor of
the Trust.
The
Net Profits Interest is passive in nature and neither the Trust nor the Trustee has any management control over or responsibility
for costs relating to the operation of the Underlying Properties. The Net Profits Interest entitles the Trust to receive 80% of
the net profits from the sale of oil and natural gas production from the Underlying Properties during the term of the Trust. The
Trust Agreement provides that the Trust’s business activities are limited to owning the Net Profits Interest and any activity
reasonably related to such ownership, including activities required or permitted by the terms of the Conveyance. As a result,
the Trust is not permitted to acquire other oil and natural gas properties or net profits interests or otherwise to engage in
activities beyond those necessary for the conservation and protection of the Net Profits Interest.
The
Trust has no employees. Administrative functions are performed by the Trustee pursuant to the Trust Agreement. The Trustee has
no authority over or responsibility for, and no involvement with, any aspect of the oil and gas operations or other activities
on the Underlying Properties. The duties of the Trustee are specified in the Trust Agreement and by the laws of the state of Delaware,
except as modified by the Trust Agreement. The Trustee’s principal duties consist of:
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collecting
cash attributable to the Net Profits Interest;
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paying
expenses, charges and obligations of the Trust from the Trust’s assets;
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distributing
distributable cash to the Trust unitholders;
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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;
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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;
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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”);
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establishing,
evaluating and maintaining a system of internal control over financial reporting in compliance
with the requirements of the Sarbanes-Oxley Act of 2002;
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enforcing
the Trust’s rights under certain agreements; and
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taking
any action it deems necessary or advisable to best achieve the purposes of the Trust.
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In
connection with the formation of the Trust, the Trust entered into several agreements with Enduro that imposed obligations upon
Enduro, including the Conveyance and a Registration Rights Agreement, which COERT assumed in connection with the Sale Transaction.
The Trustee has the power and authority under the Trust Agreement to enforce these agreements on behalf of the Trust. Additionally,
the Trustee may from time to time supplement or amend the Conveyance and the Registration Rights Agreement without the approval
of Trust unitholders in order to cure any ambiguity, to correct or supplement any defective or inconsistent provisions, to grant
any benefit to all of the Trust unitholders, to comply with changes in applicable law or to change the name of the Trust. Such
supplement or amendment, however, may not materially adversely affect the interests of the Trust unitholders.
The
Trustee may create a cash reserve to pay for future liabilities of the Trust and may authorize the Trust to borrow money to pay
administrative or incidental expenses of the Trust that exceed its cash on hand and available reserves. The Trustee may authorize
the Trust to borrow from any person, including the Trustee, the Delaware Trustee or an affiliate thereof, although none of the
Trustee, the Delaware Trustee nor any affiliate thereof intends to lend funds to the Trust. The Trustee may also cause the Trust
to mortgage its assets to secure payment of the indebtedness. The terms of such indebtedness and security interest, if funds were
loaned by the Trustee, Delaware Trustee or an affiliate thereof, would be similar to the terms that such entity would grant to
a similarly situated commercial customer with whom it did not have a fiduciary relationship. Under the terms of the Trust Agreement,
COERT has provided the Trust with a $1.2 million letter of credit to be used by the Trust in the event that its cash on hand (including
available cash reserves) is not sufficient to pay ordinary course administrative expenses. If the Trust requires more than the
$1.2 million under the letter of credit to pay administrative expenses, COERT has agreed to loan funds to the Trust necessary
to pay such expenses. If the Trust borrows funds or draws on the letter of credit, no further distributions will be made to Trust
unitholders until such amounts borrowed or drawn are repaid. The total amount drawn of $348,821 as of December 31, 2020 will be
recouped from the subsequent distribution as a reduction of NPI income received from the Sponsor.
Each
month, the Trustee pays Trust obligations and expenses and distributes to the Trust unitholders the remaining proceeds received
from the Net Profits Interest. The cash held by the Trustee as a reserve against future liabilities or for distribution at the
next distribution date may be held in a noninterest-bearing account or may be invested in:
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interest-bearing
obligations of the United States government;
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money
market funds that invest only in United States government securities;
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repurchase
agreements secured by interest-bearing obligations of the United States government; or
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bank
certificates of deposit.
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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:
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the
Trust, upon approval of the holders of at least 75% of the outstanding Trust Units, sells
the Net Profits Interest;
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the
annual cash proceeds received by the Trust attributable to the Net Profits Interest are
less than $2 million for each of any two consecutive years;
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the
holders of at least 75% of the outstanding Trust Units vote in favor of dissolution;
or
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the
Trust is judicially dissolved.
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Upon
dissolution of the Trust, the Trustee would sell all of the Trust’s assets, either by private sale or public auction, and,
after payment or the making of reasonable provision for payment of all liabilities of the Trust, distribute the net proceeds of
the sale to the Trust unitholders.
Marketing
and Post-Production Services
Pursuant
to the terms of the Conveyance, the Sponsor has the responsibility to market, or cause to be marketed, the oil and natural gas
production attributable to the Net Profits Interest in the Underlying Properties. The terms of the Conveyance restrict the Sponsor
from charging any fee for marketing production attributable to the Net Profits Interest other than fees for marketing paid to
non-affiliates. Accordingly, a marketing fee is not deducted (other than fees paid to non-affiliates) in the calculation of the
Net Profits Interest’s share of net profits. The net profits to the Trust from the sales of oil and natural gas production
from the Underlying Properties attributable to the Net Profits Interest is determined based on the same price that the Sponsor
receives for sales of oil and natural gas production attributable to the Sponsor’s interest in the Underlying Properties.
However, if the oil or natural gas is processed, the net profits receive the same processing upgrade or downgrade as the Sponsor.
The
operators of the Underlying Properties sell the oil produced from the Underlying Properties to third-party crude oil purchasers.
Oil production from the Underlying Properties is typically transported by truck from the field to the closest gathering facility
or refinery. The operators sell the majority of the oil production from the Underlying Properties under contracts using market
sensitive pricing. The price received by the operators for the oil production from the Underlying Properties is usually based
on a regional price applied to equal daily quantities in the month of delivery that is then reduced for differentials based upon
delivery location and oil quality. Natural gas produced by the operators is marketed and sold to third-party purchasers. The natural
gas is sold pursuant to contracts with such third parties, and the sales contracts are in their secondary terms and are on a month-to-month
basis. The contract prices are based on a published regional index price, after adjustments for Btu content, transportation and
related charges.
The
following purchasers individually accounted for ten percent or more of sales from the Underlying Properties that were included
in calculating the Trust’s “Income from net profits interest” for the periods presented. The table provides
the percentage represented by the purchasers during the periods presented:
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Year Ended December 31,
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2020
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2019
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ConocoPhillips
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38
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%
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31
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%
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Occidental Petroleum
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16
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%
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16
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%
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HollyFrontier
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13
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%
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12
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%
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Competition
and Markets
The
oil and natural gas industry is highly competitive. The Sponsor competes with major oil and natural gas companies and independent
oil and natural gas companies for oil and natural gas, equipment, personnel and markets for the sale of oil and natural gas. Many
of these competitors are financially stronger than the Sponsor, but even financially troubled competitors can affect the market
because of their need to sell oil and natural gas at any price to attempt to maintain cash flow. Because the Sponsor and the third-party
operators of the Underlying Properties are subject to competitive conditions in the oil and natural gas industry, the Trust’s
Net Profits Interest is indirectly subject to those same competitive conditions.
Oil
and natural gas compete with other forms of energy available to customers, primarily based on price. These alternate forms of
energy include electricity, coal and fuel oils. Changes in the availability or price of oil, natural gas or other forms of energy,
as well as business conditions, conservation, legislation, regulations and the ability to convert to alternate fuels and other
forms of energy may affect the demand for oil and natural gas.
Future
prices for oil and natural gas will directly impact Trust distributions, estimates of reserves attributable to the Trust’s
interests and estimated and actual future net revenues to the Trust. In view of the many uncertainties that affect the supply
and demand for oil and natural gas, neither the Trust nor the Sponsor can make reliable predictions of future oil and natural
gas supply and demand or future product prices. Nevertheless, lower product prices generally will result in lower distributions,
lower estimates of reserves attributable to the Trust’s interests and lower estimated and actual future net revenues to
the Trust.
All
the Trust’s assets are located in the United States. The operators of the Underlying Properties sell the oil and natural
gas produced from the Underlying Properties to third-party purchasers in the United States. Demand for natural gas generally is
higher in the winter months, but otherwise seasonal factors do not affect the Trust.
Description
of Trust Units
Each
Trust Unit is a unit of beneficial interest in the Trust and is entitled to receive cash distributions from the Trust on a pro
rata basis. Each Trust unitholder has the same rights regarding his or her Trust Units as every other Trust unitholder has regarding
his or her units. The Trust Units are in book-entry form only and are not represented by certificates. The Trust had 33,000,000
Trust Units outstanding as of March 23, 2021.
Distributions
and Income Computations
Each
month, the Trustee determines the amount of funds available for distribution to the Trust unitholders. Available funds are the
excess cash, if any, received by the Trust from the Net Profits Interest and other sources (such as interest earned on any amounts
reserved by the Trustee) that month, over the Trust’s liabilities for that month. Available funds are reduced by any cash
the Trustee decides to hold as a reserve against future liabilities. The holders of Trust Units as of the applicable record date
(generally the last business day of each calendar month) are entitled to monthly distributions payable on or before the 10th business
day after the record date. In the event that the net profits for any computation period is a negative amount, the Trust will receive
no payment for that period, and any such negative amount plus accrued interest will be deducted from gross profits in the following
computation period for purposes of determining the net profits for that following computation period.
Unless
otherwise advised by counsel or the Internal Revenue Service (“IRS”), the Trustee will treat the income and expenses
of the Trust for each month as belonging to the Trust unitholders of record on the monthly record date. Trust unitholders generally
will recognize income and expenses for tax purposes in the month the Trust receives or pays those amounts, rather than in the
month the Trust distributes the cash to which such income or expenses (as applicable) relate. Minor variances may occur. For example,
the Trustee could establish a reserve in one month that would not result in a tax deduction until a later month.
Transfer
of Trust Units
Trust
unitholders may transfer their Trust Units in accordance with the Trust Agreement. The Trustee will not require either the transferor
or transferee to pay a service charge for any transfer of a Trust Unit. The Trustee may require payment of any tax or other governmental
charge imposed for a transfer. The Trustee may treat the owner of any Trust Unit as shown by its records as the owner of the Trust
Unit. The Trustee will not be considered to know about any claim or demand on a Trust Unit by any party except the record owner.
A person who acquires a Trust Unit after any monthly record date will not be entitled to the distribution relating to that monthly
record date. Delaware law and the Trust Agreement govern all matters affecting the title, ownership or transfer of Trust Units.
Periodic
Reports
The
Trustee files all required Trust federal and state income tax and information returns. The Trustee prepares and mails to Trust
unitholders annual reports that Trust unitholders need to correctly report their share of the income and deductions of the Trust.
The Trustee also causes to be prepared and filed reports that are required to be filed under the Exchange Act and by the rules
of any securities exchange or quotation system on which the Trust Units are listed or admitted to trading, and also causes the
Trust to comply with the provisions of the Sarbanes-Oxley Act of 2002, including but not limited to, establishing, evaluating
and maintaining a system of internal control over financial reporting in compliance with the requirements of Section 404 thereof.
Each
Trust unitholder and his or her representatives may examine, for any proper purpose, during reasonable business hours, the records
of the Trust and the Trustee, subject to such restrictions as are set forth in the Trust Agreement.
Liability
of Trust Unitholders
Under
the Delaware Statutory Trust Act, Trust unitholders are entitled to the same limitation of personal liability extended to stockholders
of private corporations for profit under the General Corporation Law of the State of Delaware. The courts in jurisdictions outside
of Delaware, however, might not give effect to such limitation.
Voting
Rights of Trust Unitholders
The
Trustee or Trust unitholders owning at least 10% of the outstanding Trust Units may call meetings of Trust unitholders. The Trust
is responsible for all costs associated with calling a meeting of Trust unitholders, unless such meeting is called by the Trust
unitholders in which case the Trust unitholders are responsible for all costs associated with calling such meeting. Meetings must
be held in such location as is designated by the Trustee in the notice of such meeting. The Trustee must send notice of the time
and place of the meeting and the matters to be acted upon to all of the Trust unitholders at least 20 days and not more than 60
days before the meeting. Trust unitholders representing a majority of Trust Units outstanding must be present or represented to
have a quorum. Each Trust unitholder is entitled to one vote for each Trust Unit owned. Abstentions and broker non-votes shall
not be deemed to be a vote cast.
Unless
otherwise required by the Trust Agreement, a matter may be approved or disapproved by the affirmative vote of a majority of the
Trust Units present in person or by proxy at a meeting where there is a quorum. This is true even if a majority of the total Trust
Units did not approve it. The affirmative vote of the holders of at least 75% of the outstanding Trust Units is required to:
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amend
the Trust Agreement (except with respect to certain matters that do not adversely affect
the rights of Trust unitholders in any material respect); or
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approve
the sale of all the assets of the Trust (including the sale of the Net Profits Interest).
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At
the special meeting of Trust unitholders held on August 30, 2017, unitholders approved amendments to the Trust Agreement. In September
2017, Enduro, the Trustee and the Delaware Trustee entered into the First Amendment to Amended and Restated Trust Agreement, which
amended certain provisions of the Trust Agreement to, among other things, allow Enduro (and, therefore, following the Sale Transaction,
the Sponsor) to sell interests in the Underlying Properties free and clear of the Net Profits Interest with the approval of Trust
unitholders holding at least 50% of the then outstanding units of the Trust at a meeting held in accordance with the requirements
of the Trust Agreement. This amendment reduced the required threshold for approval of such sales from 75% to 50% of the outstanding
units of the Trust.
In
addition, certain amendments to the Trust Agreement may be made by the Trustee without approval of the Trust unitholders.
Computation
of Net Profits
The
provisions of the Conveyance governing the computation of the net profits are detailed and extensive. The following information
summarizes the material provisions of the Conveyance related to the computation of the net profits, but is qualified in its entirety
by the text of the Conveyance, which is incorporated by reference as an exhibit to this Form 10-K.
Net
Profits Interest
The
amounts paid to the Trust for the Net Profits Interest are based on, among other things, the definitions of “gross profits”
and “net profits” contained in the Conveyance and described below. Under the Conveyance, net profits are computed
monthly, and 80% of the aggregate net profits attributable to the sale of oil and natural gas production from the Underlying Properties
for each calendar month will be paid to the Trust on or before the end of the following month. The Sponsor will not pay to the
Trust any interest on the net profits held by the Sponsor prior to payment to the Trust, provided that such payments are timely
made.
“Gross
profits” means the aggregate amount received by the Sponsor from and after July 1, 2011 from sales of oil and natural
gas produced from the Underlying Properties that are not attributable to a production month that occurs prior to June 1, 2011
(after deducting the appropriate share of all royalties and any overriding royalties, production payments and other similar charges
(in each case, in existence as of June 1, 2011) and other than certain excluded proceeds, as described in the Conveyance), including
all proceeds and consideration received (i) directly or indirectly, for advance payments, (ii) directly or indirectly, under take-or-pay
and similar provisions of production sales contracts (when credited against the price for delivery of production) and (iii) under
balancing arrangements. Gross profits do not include consideration for the transfer or sale of any Underlying Property by the
Sponsor or any subsequent owner to any new owner, unless the Net Profits Interest is released (as is permitted under certain circumstances).
Gross profits also do not include any amount for oil or natural gas lost in production or marketing or used by the owner of the
Underlying Properties in drilling, production and plant operations.
“Net
profits” means, as more fully set forth in the Conveyance, gross profits less the following costs, expenses and, where
applicable, losses, liabilities and damages all as actually incurred by the Sponsor and attributable to the Underlying Properties
on or after July 1, 2011 but that are not attributable to a production month that occurs prior to July 1, 2011 (as such items
are reduced by any offset amounts, as described in the Conveyance):
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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;
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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;
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all
taxes, charges and assessments (excluding federal and state income, transfer, mortgage,
inheritance, estate, franchise and like taxes) with respect to the ownership of, or production
of hydrocarbons from, the Underlying Properties;
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all
insurance premiums attributable to the ownership or operation of the Underlying Properties
for insurance actually carried with respect to the Underlying Properties, or any equipment
located on any of the Underlying Properties, or incident to the operation or maintenance
of the Underlying Properties;
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all
amounts and other consideration for (i) rent and the use of or damage to the surface,
(ii) delay rentals, shut-in well payments and similar payments and (iii) fees for renewal,
extension, modification, amendment, replacement or supplementation of the leases included
in the Underlying Properties;
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all
amounts charged by the relevant operator as overhead, administrative or indirect charges
specified in the applicable operating agreements or other arrangements covering the Underlying
Properties or the Sponsor’s operations with respect thereto;
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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;
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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;
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all
costs and expenses for recording the Conveyance and, at the applicable times, terminations
and/or releases thereof;
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amounts
previously included in gross profits but subsequently paid as a refund, interest or penalty;
and
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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).
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As
mentioned above, the costs deducted in the net profits determination will be reduced by certain offset amounts. The offset amounts
are further described in the Conveyance, and include, among other things, certain net proceeds attributable to the treatment or
processing of hydrocarbons produced from the Underlying Properties and certain non-production revenues, including salvage value
for equipment related to plugged and abandoned wells. If the offset amounts exceed the costs during a monthly period, the ability
to use such excess amounts to offset costs will be deferred and utilized as offsets in the next monthly period to the extent such
amounts, plus accrued interest thereon, together with other offsets to costs, for the applicable month, are less than the costs
arising in such month.
The
Trust is not liable to the owners of the Underlying Properties or the operators for any operating capital or other costs or liabilities
attributable to the Underlying Properties. The Trustee expects to make distributions to Trust unitholders monthly; however, in
the event that the net profits for any computation period is a negative amount, the Trust will receive no payment for that period,
and any such negative amount plus accrued interest will be deducted from gross profits in the following computation period for
purposes of determining the net profits for that following computation period.
The
Trust uses the modified cash basis of accounting to report Trust receipts of the Net Profits Interest and payments of expenses
incurred. The Net Profits Interest represents the right to receive revenues (oil and natural gas sales), less direct operating
expenses (lease operating expenses and production and property taxes) and development expenses of the Underlying Properties, multiplied
by 80%. Cash distributions of the Trust will be made based on the amount of cash received by the Trust pursuant to terms of the
Conveyance.
Additional
Provisions
If
a controversy arises as to the sales price of any production, then for purposes of determining gross profits:
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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;
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amounts
received and promptly deposited with a non-affiliated escrow agent will not be considered
to have been received until disbursed to the Sponsor by the escrow agent; and
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amounts
received and not deposited with an escrow agent will be considered to have been received.
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The
Trustee is not obligated to return any cash received from the Net Profits Interest. Any overpayments made to the Trust by the
Sponsor due to adjustments to prior calculations of net profits or otherwise will reduce future amounts payable to the Trust until
the Sponsor recovers the overpayments plus interest at a prime rate (as described in the Conveyance).
The
Conveyance generally permits the Sponsor to transfer without the consent or approval of the Trust unitholders all or any part
of its interest in the Underlying Properties, subject to the Net Profits Interest. The Trust unitholders are not entitled to any
proceeds of a sale or transfer of the Sponsor’s interest. Except in certain cases where the Net Profits Interest is released,
following a sale or transfer, the Underlying Properties will continue to be subject to the Net Profits Interest, and the gross
profits attributable to the transferred property will be calculated, paid and distributed by the transferee to the Trust. The
Sponsor will have no further obligations, requirements or responsibilities with respect to any such transferred interests.
In
addition, the Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest
associated with any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties
in the prior 12 months, provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period,
an aggregate fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by the Sponsor
to a non-affiliate of the relevant Underlying Properties and are conditioned upon an amount equal to the fair value to the Trust
of such Net Profits Interest being treated as an offset amount against costs and expenses. In January 2019, the Sponsor sold two
producing wells and associated acreage of the Underlying Properties under this provision for a sale price of approximately $62,000,
and the Trustee released such properties from the Net Profits Interest.
As
the designated operator of a property included in the Underlying Properties, the Sponsor may enter into farm-out, operating, participation
and other similar agreements to develop the property, but any transfers made in connection with such agreements will be made subject
to the Net Profits Interest. The Sponsor may enter into any of these agreements without the consent or approval of the Trustee
or any Trust unitholder.
The
Sponsor has the right to release, surrender or abandon its interest in any Underlying Property that will no longer produce (or
be capable of producing) hydrocarbons in paying quantities (determined without regard to the Net Profits Interest). Upon such
release, surrender or abandonment, the portion of the Net Profits Interest relating to the affected property will also be released,
surrendered or abandoned, as applicable. The Sponsor also has the right to abandon an interest in the Underlying Properties if
(a) such abandonment is necessary for health, safety or environmental reasons or (b) the hydrocarbons that would have been produced
from the abandoned portion of the Underlying Properties would reasonably be expected to be produced from wells located on the
remaining portion of the Underlying Properties.
The
Sponsor must maintain books and records sufficient to determine the amounts payable for the Net Profits Interest to the Trust.
Monthly and annually, the Sponsor must deliver to the Trustee a statement of the computation of the net profits for each computation
period. The Trustee has the right to inspect and review the books and records maintained by the Sponsor during normal business
hours and upon reasonable notice. The Sponsor has further agreed to provide the Trust and Trustee with all information and services
as are reasonably necessary to fulfill the purposes of the Trust, including such accounting, bookkeeping and informational services
as may be necessary for the preparation of reports the Trust is required to prepare or file in accordance with applicable tax
and securities laws, exchange listing rules and other requirements, including reserve reports and tax returns. Following the sale
of all or any portion of the Underlying Properties, the purchaser will be bound by the obligations of the Sponsor under the Trust
Agreement and the Conveyance with respect to the portion sold.
U.S.
Federal Income Tax Matters
The
following is a summary of certain U.S. federal income tax matters that may be relevant to the Trust unitholders. This summary
is based upon current provisions of the Internal Revenue Code of 1986, as amended (the “Code”), existing and proposed
Treasury regulations thereunder and current administrative rulings and court decisions, all of which are subject to changes that
may or may not be retroactively applied. No attempt has been made in the following summary to comment on all U.S. federal income
tax matters affecting the Trust or the Trust unitholders.
The
summary has limited application to non-U.S. persons and persons subject to special tax treatment such as, without limitation:
banks, insurance companies or other financial institutions; Trust unitholders subject to the alternative minimum tax; tax-exempt
organizations; dealers in securities or commodities; regulated investment companies; real estate investment trusts; traders in
securities that elect to use a mark-to-market method of accounting for their securities holdings; non-U.S. Trust unitholders that
are “controlled foreign corporations” or “passive foreign investment companies”; persons that are S-corporations,
partnerships or other pass-through entities; persons that own their interest in the Trust Units through S-corporations, partnerships
or other pass-through entities; persons that at any time own more than 5% of the aggregate fair market value of the Trust Units;
expatriates and certain former citizens or long-term residents of the United States; U.S. Trust unitholders whose functional currency
is not the U.S. dollar; persons who hold the Trust Units as a position in a hedging transaction, “straddle”, “conversion
transaction” or other risk reduction transaction; or persons deemed to sell the Trust Units under the constructive sale
provisions of the Code. Each Trust unitholder should consult his or her own tax advisor with respect to his or her particular
circumstances.
Classification
and Taxation of the Trust
Tax
counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, in its opinion, the
Trust would be treated as a grantor trust and not as an unincorporated business entity. No ruling has been or will be requested
from the IRS or another taxing authority. The remainder of the discussion below is based on tax counsel’s opinion, at the
time of formation, that the Trust will be classified as a grantor trust for U.S. federal income tax purposes. As a grantor trust,
the Trust is not subject to U.S. federal income tax at the trust level. Rather, each Trust unitholder is considered for U.S. federal
income tax purposes to own its proportionate share of the Trust’s assets directly as though no Trust were in existence.
The income of the Trust is deemed to be received or accrued by the Trust unitholder at the time such income is received or accrued
by the Trust, rather than when distributed by the Trust. Each Trust unitholder is subject to tax on its proportionate share of
the income and gain attributable to the assets of the Trust and is entitled to claim its proportionate share of the deductions
and expenses attributable to the assets of the Trust, subject to applicable limitations, in accordance with the Trust unitholder’s
tax method of accounting and taxable year without regard to the taxable year or accounting method employed by the Trust.
The
Trust files annual information returns, reporting to the Trust unitholders all items of income, gain, loss, deduction and credit.
The Trust allocates these items of income, gain, loss, deduction and credit to Trust unitholders based on record ownership on
the monthly record dates. It is possible that the IRS or another taxing authority could disagree with this allocation method and
assert that income and deductions of the Trust should be determined and allocated on a daily or prorated basis, which could require
adjustments to the tax returns of the unitholders affected by this issue and result in an increase in the administrative expense
of the Trust in subsequent periods.
Under
current law, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest
marginal U.S. federal income tax rate applicable to long-term capital gains (generally, gains from the sale or exchange of certain
investment assets held for more than one year) and qualified dividends of individuals is generally 20%. Such marginal tax rates
may be effectively increased due to the phaseout of personal exemptions and certain limitations and prohibitions on itemized deductions.
The highest marginal U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income
and capital gains.
Section
1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts (and a reduced
1.4% tax on certain tax-exempt organizations). For these purposes, investment income generally will include a unitholder’s
allocable share of the trust’s interest and royalty income plus the gain recognized from a sale of Trust units. In the case
of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or
(ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on
such individual’s U.S. federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser
of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest
income tax bracket applicable to an estate or trust begins.
If
a taxpayer disposes of any “Section 1254 property” (certain oil, gas, geothermal or other mineral property), and the
adjusted basis of such property includes adjustments for depletion deductions under Section 611 of the Code, the taxpayer generally
must recapture the amount deducted for depletion as ordinary income (to the extent of gain realized on the disposition of the
property). This depletion recapture rule applies to any disposition of property that was placed in service by the taxpayer after
December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions
of property after March 13, 1995. The IRS likely will take the position that a unitholder must recapture depletion upon the disposition
of a unit.
Classification
of the Net Profits Interest
Tax
counsel to the Trust advised the Trust at the time of formation that, for U.S. federal income tax purposes, based upon the reserve
report and representations made by the Trust regarding the expected economic life of the Underlying Properties and the expected
duration of the Net Profits Interest, in its opinion the Net Profits Interest attributable to proved developed reserves will and
the Net Profits Interest attributable to proved undeveloped reserves should be treated as continuing, nonoperating economic interests
in the nature of royalties payable out of production from the mineral interests they burden. No assurance can be given that the
IRS or another taxing authority will not assert that the Net Profits Interest should be treated differently. Any such different
treatment could affect the amount, timing and character of income, gain or loss in respect of an investment in Trust Units.
Reporting
Requirements for Widely-Held Fixed Investment Trusts
The
Trustee assumes that some Trust Units are held by middlemen, as such term is broadly defined in the Treasury regulations (and
includes custodians, nominees, certain joint owners and brokers holding an interest for a custodian street name, collectively
referred to herein as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed
investment trust (“WHFIT”) for U.S. federal income tax purposes. The Bank of New York Mellon Trust Company, N.A.,
601 Travis Street, Houston, Texas 77002, telephone number 1-512-236-6545, is the representative of the Trust that will provide
the tax information in accordance with applicable Treasury regulations governing the information reporting requirements of the
Trust as a WHFIT. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of unitholders, and not the Trustee
of the Trust, are solely responsible for complying with the information reporting requirements under the Treasury regulations
with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unitholders whose
Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by
the middlemen with respect to the Trust Units. Any generic tax information provided by the Trustee of the Trust is intended to
be used only to assist Trust unitholders in the preparation of their federal and state income tax returns.
Available
Trust Tax Information
In
compliance with the Treasury regulations reporting requirements for WHFITs and the dissemination of Trust tax reporting information,
the Trustee provides a generic tax information reporting booklet which is intended to be used only to assist Trust unitholders
in the preparation of their federal and state income tax returns. This tax information booklet can be obtained at www.permianvilleroyaltytrust.com.
Environmental
Matters and Regulation
General.
For purposes of the discussion in this section, the oil and natural gas production operations conducted on the properties
that are subject to the Net Profits Interest are referred to as the “Sponsor’s operations.” The Sponsor’s
oil and natural gas exploration and production operations are subject to stringent and comprehensive federal, regional, state
and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental
protection. These laws and regulations may impose significant obligations on the Sponsor’s operations, including requirements
to:
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obtain
permits to conduct regulated activities;
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limit
or prohibit drilling activities on certain lands lying within wilderness, wetlands and
other protected areas;
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restrict
the types, quantities and concentration of materials that can be released into the environment
in the performance of drilling, completion and production activities;
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initiate
investigatory and remedial measures to mitigate pollution from former or current operations,
such as restoration of drilling pits and plugging of abandoned wells; and
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apply
specific health and safety criteria addressing worker protection.
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Failure
to comply with environmental laws and regulations may result in the assessment of significant administrative, civil and criminal
sanctions, including monetary penalties, the imposition of joint and several liability, investigatory and remedial obligations,
and the issuance of injunctions limiting or prohibiting some or all of the Sponsor’s operations. Moreover, these laws, rules
and regulations may restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory
burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability.
The Sponsor has advised the Trustee that it believes that it is in substantial compliance with all existing environmental laws
and regulations applicable to its current operations and that its continued compliance with existing requirements will not have
a material adverse effect on the cash distributions to the Trust unitholders. Although the Trump Administration had taken steps
aimed at reducing federal regulatory burdens and costs for oil and natural gas production operations, the recent trend in environmental
regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, any changes
in environmental laws and regulations or re-interpretation of enforcement policies that result in more stringent and costly construction,
drilling, water management, completion, emission or discharge limits or waste handling, disposal or remediation obligations could
have a material adverse effect on the Sponsor’s development expenses, results of operations and financial position. The
Sponsor may be unable to pass on those increases to its customers. Moreover, accidental releases or spills may occur in the course
of the Sponsor’s operations, and there can be no assurance that the Sponsor will not incur significant costs and liabilities
as a result of such releases or spills, including any third-party claims for damage to property, natural resources or persons.
The
following is a summary of certain existing environmental, health and safety laws and regulations to which the Sponsor’s
business operations are subject.
Hazardous
substance and wastes. The Comprehensive Environmental Response, Compensation and Liability Act, or “CERCLA,” also
known as the Superfund law, and comparable state laws impose liability without regard to fault or the legality of the original
conduct on certain classes of persons who are considered to be responsible for the release of a “hazardous substance”
into the environment. Under CERCLA, these “responsible persons” may include the owner or operator of the site where
the release occurred, and entities that transport, dispose of or arrange for the transport or disposal of hazardous substances
released at the site. These responsible persons may be subject to joint and several strict liability for the costs of cleaning
up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of
certain health studies. CERCLA also authorizes the U.S. Environmental Protection Agency (“EPA”) and, in some instances,
third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible
classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims
for personal injury and property damage allegedly caused by the hazardous substances released into the environment. The Sponsor
generates materials in the course of its operations that may be regulated as hazardous substances.
The
Resource Conservation and Recovery Act, or “RCRA,” and comparable state laws regulate the generation, transportation,
treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer
some or all the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced
waters and most of the other wastes associated with the exploration, production and development of crude oil or natural gas are
currently regulated under the RCRA as non-hazardous wastes. Nevertheless, it is possible that certain oil and natural gas exploration
and production wastes (“E&P Wastes”) now classified as non-hazardous could be classified as hazardous wastes in
the future. For example, in December 2016, the EPA and environmental groups entered a consent decree to address the EPA’s
alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production-related
oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking
no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes
or to sign a determination that revision of the regulations is not necessary. The EPA fulfilled its obligation under the consent
decree by issuing a determination on April 23, 2019 that revisions to existing RCRA Subtitle D regulations governing oil and natural
gas wastes are not necessary, along with a report supporting that determination. In addition, the Sponsor generates industrial
wastes in the ordinary course of its operations that may be regulated as hazardous wastes. Such wastes must be properly tested,
characterized and disposed of according to state and federal regulations.
The
properties upon which the Sponsor conducts its operations have been used for oil and natural gas exploration and production for
many years. Although the Sponsor and, as applicable, the Sponsor’s predecessor, Enduro, may have utilized operating and
disposal practices that were standard in the industry at the time, petroleum hydrocarbons and wastes may have been disposed of
or released at or from the real properties upon which the Sponsor conducts its operations, or at or from other, offsite locations,
where these petroleum hydrocarbons and wastes have been taken for recycling or disposal. In addition, the properties upon which
the Sponsor conducts its operations may have been operated by third parties or by previous owners or operators whose treatment
and disposal of hazardous substances, wastes or hydrocarbons was not under the Sponsor’s control. These properties and the
petroleum hydrocarbons and wastes disposed or released at or from these properties may be subject to CERCLA, RCRA and analogous
state laws. Under such laws, the Sponsor could be required to investigate, remove or remediate previously disposed wastes, to
clean up contaminated property and to perform remedial operations such as restoration of pits and plugging of abandoned wells
to prevent future contamination or to pay some or all of the costs of any such action.
Water
discharges. The federal Clean Water Act (“CWA”) and analogous state laws impose restrictions and strict controls
regarding the discharge of pollutants into water of the United States and waters of the state, respectively. Pursuant to the CWA
and analogous state laws, permits must be obtained to discharge pollutants into state waters or waters of the United States. Any
such discharge of pollutants into regulated waters must be performed in accordance with the terms of the permit issued by EPA
or the analogous state agency. The discharge of wastewater from most onshore oil and gas activities exploration and production
activities is currently prohibited east of the 98th meridian. Additionally, in June 2016, the EPA issued a final rule
implementing wastewater pretreatment standards that prohibit onshore unconventional oil and natural gas extraction facilities
from sending certain wastewater directly to publicly owned treatment works (“POTW”). Unconventional extraction facilities
are allowed by 40 CFR Part 437 to send wastewater to an off-site private centralized wastewater treatment (“CWT”)
facility in most circumstances. CWT facilities can either discharge treated water directly to surface waters or send it to a POTW.
In 2018, the EPA concluded a study of the treatment and discharge of oil and gas wastewater that could lead to changes in requirements
for discharge of produced water under Part 437, including more stringent requirements or a prohibition on discharge of produced
water from CWT facilities. Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge
requirements may result in increased costs.
The
discharge of dredge and fill material in waters of the United States, including wetlands, is also prohibited unless authorized
by a permit issued by the U.S. Army Corps of Engineers (“ACE”). CWA Section 401 provides that the applicant for an
individual Section 404 ACE permit for the discharge of dredge and fill materials must notify the state in which the discharge
will occur and provide an opportunity for the state to determine if the discharge will comply with the state’s approved
water quality program. In some instances, this process could result in delay in issuance of the permit, more stringent permit
requirements, or denial of the permit.
How
the EPA and the ACE define “waters of the United States” (“WOTUS”) can impact the Sponsor’s regulatory
and permitting obligations under the CWA. The EPA and the ACE promulgated rules defining the scope of WOTUS that became effective
in September 2015. On October 22, 2019, the EPA and the ACE published a final rule that repealed the 2015 definition of WOTUS
and re-codified longstanding regulatory definitions of WOTUS that existed prior to the 2015 rule to promote regulatory consistency
across the United States. On April 21, 2020, the EPA and the ACE issued a revised regulation (the “2020 rule”) that
narrowed the definition from the 2015 rule. Litigation has been filed on the 2020 rule, but it is currently effective in all jurisdictions.
In January 2021, President Biden issued an Executive Order announcing that the new administration would review the 2020 rule,
and the administration has asked that litigation on the 2020 rule be stayed while it considers how to proceed. To the extent that
the Sponsor must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other WOTUS,
the Sponsor could face increased costs and delays associated with obtaining such permits under any broader definition of WOTUS
that expands the scope of CWA jurisdiction.
The
Oil Pollution Act of 1990, as amended, or OPA, amends the CWA and establishes strict liability and natural resource damages liability
for unauthorized discharges of oil into waters of the United States. The OPA requires measures to be taken to prevent the accidental
discharge of oil into waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include
inspection and maintenance programs to minimize spills from oil storage and conveyance systems; the use of secondary containment
systems to prevent spills from reaching nearby waterbodies; proof of financial responsibility to cover environmental cleanup and
restoration costs that could be incurred in connection with an oil spill; and the development and implementation of spill prevention,
control and countermeasure (“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators
of facilities in certain instances to strict, joint and several liability for all containment and cleanup costs and certain other
damages arising from a spill. The Sponsor has developed and implemented SPCC plans for the Underlying Properties as required under
the CWA.
Hydraulic
fracturing. Various federal and state initiatives are underway to regulate, or further investigate, the environmental impacts
of hydraulic fracturing, a practice that involves the pressurized injection of water, chemicals and other substances into rock
formation to stimulate production of oil and natural gas. The U.S. Congress has considered legislation to amend the federal Safe
Drinking Water Act (“SDWA”) to subject hydraulic fracturing operations to regulation under the SDWA’s Underground
Injection Control Program and to require the disclosure of chemicals used in the hydraulic fracturing process. Any such legislation
could make it easier for third parties opposed to hydraulic fracturing to initiate legal proceedings against companies. In 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 to POTWs. EPA is conducting a related study of oil and gas extraction
wastewater at private wastewater treatment facilities. In March 2015, the federal Bureau of Land Management (“BLM”)
released a final rule establishing new or more stringent standards for performing hydraulic fracturing operations on federal and
tribal lands. Several states, trade groups and companies have challenged the legality of the BLM rule in federal court. 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 of Appeals. BLM announced in March 2017 that it intended
to rescind the rule. On December 29, 2017, BLM published a final rule that rescinded the 2015 hydraulic fracturing rule.
On
August 16, 2012 the EPA published final rules that extend New Source Performance Standards (“NSPS”) and National Emission
Standards for Hazardous Air Pollutants (“NESHAPs”) to certain exploration and production operations. The final rule
requires the use of reduced emission completions or “green completions” on all hydraulically-fractured gas wells constructed
or refractured after January 1, 2015. The EPA received numerous requests for reconsideration of these rules from both industry
and the environmental community, and court challenges to the rules were also filed. In response to some of these challenges, the
EPA amended the rule to extend compliance dates for certain storage vessels and may issue additional revised rules in response
to additional such requests in the future. Only a portion of these new rules appear to affect the Sponsor’s operations at
this time by requiring new air emissions controls, equipment modification, maintenance, monitoring, recordkeeping and reporting.
Although these new requirements will increase the Sponsor’s operating and capital expenditures and it is possible that the
EPA will adopt further regulation that could further increase the Sponsor’s operating and capital expenditures, the Sponsor
does not currently expect such existing and new regulations will have a material adverse impact on its operations or financial
results.
Some
states have adopted, and other states are considering adopting, regulations that could restrict or impose additional requirements
relating to hydraulic fracturing in certain circumstances, including the disclosure of information regarding the substances used
in the hydraulic fracturing process. Such federal or state legislation could require the disclosure of chemical constituents used
in the fracturing process to state or federal regulatory authorities who could then make such information publicly available.
Disclosure of chemicals used in the fracturing process could make it easier for third parties opposing hydraulic fracturing to
initiate legal proceedings against producers and service providers based on allegations that specific chemicals used in the fracturing
process could adversely affect groundwater. In addition, if hydraulic fracturing is regulated at the federal level, the Sponsor’s
and the third-party operators’ fracturing activities could become subject to additional permit requirements or operational
restrictions, to associated permitting delays and potential increases in costs. In December 2014, the Governor of New York announced
that the state would maintain its moratorium on hydraulic fracturing in the state. Further, some local governments, including
in Texas, have imposed moratoria on drilling permits within city limits so that local ordinances may be reviewed to assess their
adequacy to address such activities. Similar measures could be considered or implemented in the jurisdictions in which the Underlying
Properties are located.
Air
emissions. The federal Clean Air Act (“CAA”), as amended, and comparable state laws restrict the emission of air
pollutants from many sources through air emissions permitting and regulatory programs and also impose various monitoring and reporting
requirements. These laws and regulations may require the Sponsor to obtain pre-approval for the construction or modification of
certain projects or facilities expected to produce or significantly increase air emissions, and to comply with stringent air emissions
permit requirements or in utilize specific equipment or technologies to control emissions.
The
EPA has established pollution control standards for oil and gas sources under the CAA. In 2012, the EPA adopted federal New Source
Performance Standards (“NSPS”) that require the reduction of volatile organic compound emissions from certain fractured
and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced
emission completions, also known as “green completions.” These regulations also establish specific new requirements
regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage
vessels.
The
EPA is also charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which
can indirectly impact the Sponsor’s operations. The CAA directs the EPA to review each NAAQS every five years to ensure
that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards,
and in October 2015, the EPA lowered the ozone NAAQS from 75 to 70 parts per billion. In December 2020, the EPA published a final
rule that retained without revision the 2015 NAAQS ozone standard. The new administration will have an opportunity to revisit
the ozone NAAQS. In addition, on January 20, 2021, President Biden issued an executive order calling on the EPA to propose a Federal
Implementation Plan for the ozone standard for certain states by January 2022, in response to those states’ failure to submit
an adequate state plan for the control of ozone precursor emissions from certain oil and gas sources. State or federal implementation
of the NAAQS could result in stricter permitting or regulatory requirements, delay or prohibit the Sponsor’s ability to
obtain such permits, and result in increased expenditures for pollution control equipment. Although the Sponsor may be required
to incur certain capital expenditures during the next few years for air pollution control equipment or other air emissions-related
issues, at this time the Sponsor does not expect that such requirements will have a material adverse effect on its operations.
Climate
change. In response to findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”)
may present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of greenhouse
gases under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles, preconstruction
and operating permit requirements for certain large stationary sources, and methane emissions standards for certain new, modified
and reconstructed oil and gas sources. The EPA also has adopted rules requiring the reporting of GHG emissions from specified
large greenhouse gas emission sources in the United States, as well as certain onshore oil and natural gas production facilities,
on an annual basis.
In
December 2015, the EPA finalized rules that added new sources to the scope of its GHG monitoring and reporting rule. These new
sources include gathering and boosting facilities. The revisions also include the addition of well identification reporting requirements
for certain facilities. In addition, in June 2016 the EPA published a final rule that requires operators to reduce methane emissions
from certain new, modified or reconstructed oil and gas facilities, including production, processing, transmission and storage
activities (“Methane Rule”). Following the November 2016 presidential election and change in administrations, the
EPA convened a reconsideration proceeding that culminated in a 2020 final rule that eliminated the obligation to control methane
emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements because they serve to
control emissions of other pollutants. However, on January 20, 2021, President Biden issued an executive order calling on the
EPA to, among other things, consider a proposed rule suspending, revising or rescinding those 2020 amendments to the Methane Rule
by September 2021. That same order directs the EPA to propose new rules to establish standards of performance and emission guidelines
for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration
and production, transmission, processing, and storage segments, by September 2021. The ultimate fate of the Methane Rule and any
related requirements for existing sources is unclear. Nevertheless, regulations promulgated under the CAA may require the Sponsor
to incur development expenses to install and utilize specific equipment, technologies, or work practices to control methane emissions
from its operations.
More
than one-third of the states have begun taking actions to control and/or reduce emissions of GHGs, primarily through the planned
development of GHG emission inventories and/or regional GHG cap and trade programs. Although most of the state-level initiatives
have to date focused on large sources of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources
of emissions could become subject to GHG emission limitations or allowance purchase requirements in the future. In addition, from
time to time Congress has considered adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change
regulatory and legislative initiatives could have a material adverse effect on the Sponsor’s business, capital expenditures,
financial condition and results of operations.
At
the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations
Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their
contributions and set greenhouse gas emission reduction goals every five years beginning in 2020. While the Agreement did not
impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements.
In November 2019, however, plans were formally announced for the U.S. to withdraw from the Paris Agreement, and the U.S.’s
withdrawal from the Paris Agreement took effect on November 4, 2020. On January 20, 2021, President Biden issued an executive
order commencing the process to reenter the Paris Agreement, although the emissions pledges in connection with that effort have
not yet been updated. The U.S. formally rejoined the Paris Agreement in February 2021. The Trust cannot predict whether re-entry
into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements
will cause the Sponsor to incur material costs.
In
a separate executive order issued on January 20, 2021, President Biden asked the heads of all executive departments and agencies
to review and take action to address any Federal regulations, orders, guidance documents, policies and any similar agency actions
promulgated during the prior administration that may be inconsistent with or present obstacles to the administration’s stated
goals of protecting public health and the environment, and conserving national monuments and refuges. A preliminary list must
be provided to the Office of Management and Budget within 30 days of the order. Regulations specifically mentioned for review
and possible suspension, revision or rescission include the Methane Rule, and the EPA was ordered to, among other things, propose
new regulations to establish comprehensive standards for performance and emission guidelines for methane from existing oil and
gas operations by September 2021. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse
Gases, which is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social
cost of carbon,” “social cost of nitrous oxide” and “social cost of methane,” which are “the
monetized damages associated with incremental increased in greenhouse gas emissions,” including “changes in net agricultural
productivity, human health, property damage from increased flood risk, and the value of ecosystem services.” Various recommendations
from the Working Group are due beginning June 1, 2021 and final recommendations no later than January 2022.
The
adoption and implementation of regulations imposing reporting obligations on, or limiting emissions of GHGs from, the Sponsor’s
equipment and operations could require the Sponsor to incur costs to reduce emissions of GHGs associated with its operations or
could adversely affect demand for the natural gas it produces. Legislation or regulations that may be adopted to address climate
change could also affect the markets for the Sponsor’s products by making its products more or less desirable than competing
sources of energy. To the extent that its products are competing with higher GHG-emitting energy sources, the Sponsor’s
products may become more desirable in the market with more stringent limitations on GHG emissions. To the extent that its products
are competing with lower GHG-emitting energy, the Sponsor’s products may become less desirable in the market with more stringent
limitations on greenhouse gas emissions. The Sponsor cannot predict with any certainty at this time how these possibilities may
affect its operations.
Finally,
some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes
that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic
events. If any such significant physical effects were to occur, they could have an adverse effect on the Sponsor’s assets
and operations and cause the Sponsor to incur costs in preparing for and responding to them. Additionally, energy needs could
increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those conditions.
National
Environmental Policy Act. Oil and natural gas exploration, development and production activities on federal lands are subject
to the National Environmental Policy Act, as amended (“NEPA”). NEPA requires federal agencies, including the Department
of the Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course
of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative
impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made
available for public review and comment. However, for those current activities as well as for future or proposed exploration and
development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required.
This process has the potential to delay the development of oil and natural gas projects.
Endangered
Species Act. The federal Endangered Species Act and similar state statutes restrict activities that may affect endangered
and threatened species or their habitats. If endangered species are located in areas of the Underlying Properties where seismic
surveys, development activities or abandonment operations may be conducted, the work could be prohibited, delayed or expensive
mitigation may be required. On August 27, 2019, the U. S. Fish and Wildlife Service published a final rule adopting several changes
to the federal regulations that implement the ESA, including changes to the procedures and criteria for listing or removing species
from the Lists of Endangered and Threatened Wildlife and Plants and for designating critical habitat. In January 2021, President
Biden issued an Executive Order announcing that the new administration would initiate a review of the 2019 amendments to the ESA
rules. The designation of previously unidentified endangered or threatened species could cause the Sponsor to incur additional
costs arising from species protection measures or could result in limitations on exploration and production activities that could
have an adverse impact on the ability to develop and produce reserves from the Underlying Properties.
Employee
health and safety. The operations of the Sponsor are subject to a number of federal and state laws and regulations, including
the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, whose purpose is to protect
the health and safety of workers. In addition, the OSHA hazard communication standard, the EPA community right-to-know regulations
under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information
be maintained concerning hazardous materials used or produced in operations and that this information be provided to employees,
state and local government authorities and citizens.
Where
You Can Find Other Information
The
Trust maintains a website at http://www.permianvilleroyaltytrust.com. The Trust’s filings under the Exchange Act are available
at this website and are also available electronically from the website maintained by the SEC at http://www.sec.gov. In addition,
the Trust will provide electronic copies of its recent filings free of charge to the Trust unitholders upon request to the Trustee.
Summary
of Risk Factors
The
risk factors summarized and detailed below could materially harm production from the Underlying Properties, operating results
and/or the Trust’s financial condition, adversely affect proceeds to the Trust and cash distributions to Trust unitholders,
and/or cause the price of the Trust units to decline. These are not all the risks the Trust faces, and other factors not presently
known to the Trust or that the Trust currently believes are immaterial may also affect the Trust if they occur. These
risks and uncertainties include, but are not limited to, the following:
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Prices
of oil and natural gas fluctuate, and lower prices could reduce proceeds to the Trust
and cash distributions to unitholders;
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The
ongoing COVID-19 pandemic and related economic turmoil have affected and could continue
to adversely affect proceeds to the Trust and quarterly cash distributions to unitholders;
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Actual
reserves and future production may be less than current estimates, which could reduce
cash distributions by the Trust and the value of the Trust Units;
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The
ability or willingness of OPEC and other oil exporting nations to set and maintain production
levels has a significant impact on oil and natural gas commodity prices, which could
reduce the amount of cash available for distribution to Trust unitholders;
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Third
party operators are the operators of substantially all of the wells on the Underlying
Properties and, therefore, the Sponsor is not in a position to control the timing of
development efforts, the associated costs or the rate of production of the reserves on
such properties;
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The
bankruptcy of operators could impede the operation of wells;
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Developing
oil and natural gas wells and producing oil and natural gas are costly and high-risk
activities with many uncertainties that could adversely affect future production from
the Underlying Properties;
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Shortages
of equipment, services and qualified personnel could increase costs of developing and
operating the Underlying Properties and result in a reduction in the amount of cash available
for distribution to the Trust unitholders;
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The
generation of profits for distribution by the Trust depends in part on access to and
operation of gathering, transportation and processing facilities. Any limitation in the
availability of those facilities could interfere with sales of oil and natural gas production
from the Underlying Properties;
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Adverse
developments in Texas, Louisiana or New Mexico could adversely impact the results of
operations and cash flows of the Underlying Properties and reduce the amount of cash
available for distributions to Trust unitholders;
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The
reserves attributable to the Underlying Properties are depleting assets and production
from those reserves will diminish over time. Furthermore, the Trust is precluded from
acquiring other oil and natural gas properties or net profits interests to replace the
depleting assets and production;
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The
amount of cash available for distribution by the Trust will be reduced by the amount
of any costs and expenses related to the Underlying Properties and other costs and expenses
incurred by the Trust;
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The
Sponsor’s ability to perform its obligations to the Trust could be limited by restrictions
under its debt agreements;
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The
bankruptcy of the Sponsor or any of the third-party operators could impede the operation
of the wells and the development of the proved undeveloped reserves;
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In
the event of the bankruptcy of the Sponsor, if a court were to hold that the Net Profits
Interest was part of the bankruptcy estate, the Trust may be treated as an unsecured
creditor with respect to the Net Profits Interest attributable to properties in Louisiana
and New Mexico;
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The
Trust is passive in nature and neither the Trust nor the Trust unitholders have any ability
to influence the Sponsor or control the operations or development of the Underlying Properties;
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The
Sponsor may transfer all or a portion of the Underlying Properties at any time without
Trust unitholder consent, subject to specified limitations;
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Under
certain circumstances, the Trustee must sell the Net Profits Interest and dissolve the
Trust prior to the expected termination of the Trust. As a result, Trust unitholders
may not recover their investment;
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Conflicts
of interest could arise between the Sponsor and its affiliates, on the one hand, and
the Trust and the Trust unitholders, on the other hand;
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The
Trust is administered by a Trustee who cannot be replaced except by a majority vote of
the Trust unitholders at a special meeting which may make it difficult for Trust unitholders
to remove or replace the Trustee;
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If
the Trust cannot meet the New York Stock Exchange continued listing requirements, the
NYSE may delist the Trust units;
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The
trading price for the Trust Units may not reflect the value of the Net Profits Interest
held by the Trust;
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The
operations of the Underlying Properties are subject to environmental laws and regulations
that could adversely affect the cost, manner or feasibility of conducting operations
on them or result in significant costs and liabilities;
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The
operations on the Underlying Properties are subject to complex federal, state, local
and other laws and regulations that could adversely affect the cost, manner or feasibility
of conducting operations on them or expose the operator to significant liabilities;
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Climate
change laws and regulations restricting emissions of “greenhouse gases” could
result in increased operating costs and reduced demand for the oil and natural gas that
the operators produce while the physical effects of climate change could disrupt their
production and cause them to incur significant costs in preparing for or responding to
those effects;
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Federal
and state legislative and regulatory initiatives relating to hydraulic fracturing could
result in increased costs and additional operating restrictions or delays as well as
adversely affect the services of the operators of the Underlying Properties;
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Cyber-attacks
or other failures in telecommunications or information technology systems could result
in information theft, data corruption and significant disruption of the Sponsor’s
business operations;
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If
the IRS were to determine (and be sustained in that determination) that the Trust is
not a “grantor trust” for U.S. federal income tax purposes, the Trust could
be subject to more complex and costly tax reporting requirements that could reduce the
amount of cash available for distribution to Trust unitholders;
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Unitholders
are required to pay taxes on their share of the Trust’s income even if they do
not receive any cash distributions from the Trust.
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BUSINESS
AND OPERATING RISKS
Prices
of oil and natural gas fluctuate, and lower prices could reduce proceeds to the Trust and cash distributions to unitholders.
The
Trust’s reserves and monthly cash distributions are highly dependent upon the prices realized from the sale of oil and natural
gas. Oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond
the control of the Trust and the Sponsor. These factors include, among others:
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regional,
domestic and foreign supply and perceptions of supply of oil and natural gas;
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the
level of demand and perceptions of demand for oil and natural gas;
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political
conditions or hostilities in oil and natural gas producing regions;
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anticipated
future prices of oil and natural gas and other commodities;
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weather
conditions and seasonal trends;
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technological
advances affecting energy consumption and energy supply;
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U.S.
and worldwide economic conditions;
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the
occurrence or threat of epidemic or pandemic diseases, such as the recent outbreak of coronavirus or any government response to
such occurrence or threat;
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the
price and availability of alternative fuels;
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the
proximity, capacity, cost and availability of gathering and transportation facilities;
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the
volatility and uncertainty of regional pricing differentials;
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governmental
regulations and taxation;
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energy
conservation and environmental measures; and
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Crude
oil prices declined sharply in the first quarter of 2020 in response to the economic effects of the COVID-19 pandemic and the
announcement of planned production increases by Saudi Arabia. Low oil and natural gas prices will reduce profits to which the
Trust is entitled, which will reduce the amount of each available for distribution to unitholders, and may ultimately reduce the
amount of oil and natural gas that is economically viable to produce from the Underlying Properties. As a result, the operators
of the Underlying Properties could determine during periods of low commodity prices to shut-in or curtail production from wells
on the Underlying Properties, or even plug and abandon marginal wells that otherwise may have been allowed to continue to produce
for a longer period under conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably
believes that the well or property can no longer produce oil or natural gas in commercially paying quantities. This could result
in termination of the Net Profits Interest relating to the abandoned well or property.
The
Underlying Properties are sensitive to decreasing commodity prices. The commodity price sensitivity is due to a variety of factors
that vary from well to well, including the costs associated with water handling and disposal, chemicals, surface equipment maintenance,
downhole casing repairs and reservoir pressure maintenance activities that are necessary to maintain production. As a result,
decreasing commodity prices may cause the expenses of certain wells to exceed the well’s revenue, in which case the operator
may decide to shut-in the well or plug and abandon the well. This scenario could reduce future cash distributions to Trust unitholders.
The
Sponsor has not entered into any hedge contracts relating to oil and natural gas volumes expected to be produced on behalf of
the Trust, and the terms of the Conveyance of the Net Profits Interest prohibit the Sponsor from entering into new hedging arrangements
burdening the Trust. As a result, all production in which the Trust has an interest is unhedged, and the amount of the cash distributions
is subject to the possibility of greater fluctuations due to changes in oil and natural gas prices.
The
ongoing COVID-19 pandemic and related economic turmoil have affected and could continue to adversely affect proceeds to the Trust
and quarterly cash distributions to unitholders.
The
global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020 and continuing through
the beginning of 2021. The ongoing COVID-19 pandemic has reached more than 200 countries and has continued to be a rapidly evolving
economic and public health situation. The pandemic has resulted in widespread adverse impacts on the global economy, and there
is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and the extent and duration of governmental
and other measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders and business
and government shutdowns. State and local authorities have also implemented multi-step policies with the goal of re-opening. However,
certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases.
Furthermore,
the impact of the pandemic has led to significant global economic contraction generally, and in the oil and gas industry in particular,
which experienced a significant downturn during 2020 and into 2021. Since the beginning of 2020, the West Texas Intermediate spot
price of crude oil has ranged widely in response to the economic effects of the COVID-19 pandemic and the dispute over production
levels between Russia and the members of OPEC. Oil and natural gas prices are expected to continue to be volatile as a result
of the near-term production increases and the COVID-19 pandemic and as changes in oil and natural gas inventories, industry demand
and national and economic performance are reported, and the Trust cannot predict when prices will improve and stabilize. The Trust
cannot predict the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil
and natural gas markets will have on the Sponsor’s business, financial condition and results of operations or on proceeds
to the Trust and the Trust’s reserves and quarterly cash distributions to unitholders due to numerous uncertainties.
The
extent to which the COVID-19 pandemic negatively affects the operators of and production from the Underlying Properties will depend
on the severity, location and duration of the effects and spread of COVID-19, the actions undertaken by federal, state and local
governments and health officials to contain the virus or treat its effects, and how quickly and to what extent economic conditions
improve and normal business and operating conditions resume. A
prolonged period of low crude oil and natural gas prices will adversely affect the operators of the Underlying Properties. If
commodity prices for crude oil and natural gas remain volatile and below historical levels, monthly cash distributions to unitholders
will be substantially lower than historical distributions, and in certain periods there may be no distribution to unitholders.
Continued low oil and natural gas prices may ultimately reduce the amount of oil and natural
gas that is economically viable to produce from the Underlying Properties. As a result, the operators of the Underlying Properties
could determine during periods of low commodity prices to shut-in or curtail production from wells on the Underlying Properties,
or even plug and abandon marginal wells that otherwise may have been allowed to continue to produce for a longer period under
conditions of higher prices. Specifically, an operator may abandon any well or property if it reasonably believes that the well
or property can no longer produce oil or natural gas in commercially paying quantities, which could result in termination of the
Net Profits Interest relating to the abandoned well or property. Future downward revisions in actual production volumes
relative to current forecasts, higher than expected operating costs, or lower than anticipated commodity prices could result in
recognition of impairment in future periods.
The
ultimate impact of COVID-19 will depend on future developments, which are highly uncertain, difficult to predict and largely outside
of the Trust’s control, including, among others, the continued spread, duration and severity of the pandemic outbreak; the
occurrence, spread, duration and severity of any subsequent wave or waves of outbreaks; the consequences of governmental and other
measures designed to prevent the spread of the virus; the development of effective treatments; actions taken by governmental authorities,
the Sponsor’s customers and other third parties; workforce availability; and the timing and extent to which normal economic
and operating conditions resume.
To
the extent COVID-19 adversely affects production from the Underlying Properties or the business, results of operations and financial
condition of the operators of the Underlying Properties, it may also have the effect of heightening many of the other risks described
in this Form 10-K.
Actual
reserves and future production may be less than current estimates, which could reduce cash distributions by the Trust and the
value of the Trust Units.
The
value of the Trust Units and the amount of future cash distributions to the Trust unitholders will depend upon, among other things,
the accuracy of the reserves and future production estimated to be attributable to the Trust’s interest in the Underlying
Properties. It is not possible to measure underground accumulations of oil and natural gas in an exact way, and estimating reserves
is inherently uncertain. Ultimately, actual production and revenues for the Underlying Properties could vary both positively and
negatively and in material amounts from estimates. Furthermore, direct operating expenses and development expenses relating to
the Underlying Properties could be substantially higher than current estimates. Petroleum engineers are required to make subjective
estimates of underground accumulations of oil and natural gas based on factors and assumptions that include:
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historical
production from the area compared with production rates from other producing areas;
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oil
and natural gas prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes
and development expenses; and
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the
assumed effect of expected governmental regulation and future tax rates.
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Changes
in these assumptions and amounts of actual direct operating expenses and development expenses could materially decrease reserve
estimates. In addition, the quantities of recovered reserves attributable to the Underlying Properties may decrease in the future
as a result of future decreases in the price of oil or natural gas.
The
reserve report estimating the Trust’s proved reserves, future production and income attributable to the Trust’s interests
in the Underlying Properties as of December 31, 2020 was prepared, in accordance with applicable regulations, using an average
of the NYMEX first-day-of-the-month commodity price during the 12-month period ending on December 31, 2020 as required by the
SEC. The applicable prices for 2020 were $39.57 per Bbl of oil and $1.985 per Mcf of natural gas.
The
ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact
on oil and natural gas commodity prices, which could reduce the amount of cash available for distribution to Trust unitholders.
OPEC
is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken
by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and
pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production
cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these
oil production cuts. However, those negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction
in export prices and Russia announced that all previously agreed upon oil production cuts would expire on April 1, 2020. These
actions led to an immediate and steep decrease in oil prices, which briefly reached a closing NYMEX price low of negative $37.63
per Bbl of crude oil in April 2020. Although OPEC has since agreed to certain production cuts, prices in the oil and gas market
have remained depressed, as the oversupply and lack of demand in the market persist. There can be no assurance that OPEC members
and other oil exporting nations will agree to future production cuts or other actions to support and stabilize oil prices, nor
can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions
to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could
adversely affect the financial condition and economic performance of the operators of the underlying properties and may reduce
the net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available
for distribution to Trust unitholders.
Third
party operators are the operators of substantially all of the wells on the Underlying Properties and, therefore, the Sponsor is
not in a position to control the timing of development efforts, the associated costs or the rate of production of the reserves
on such properties.
As
of December 31, 2020, substantially all of the wells on the Underlying Properties were operated by third party operators. As a
result, the Sponsor has limited ability to exercise influence over, and control the risks or costs associated with, the operations
of these properties. The failure of a third party operator to adequately or efficiently perform operations, a third party operator’s
breach of the applicable operating agreements or a third party operator’s failure to act in ways that are in the Sponsor’s
or the Trust’s best interests could reduce production and revenues. Further, none of the third-party operators of the Underlying
Properties is obligated to undertake any development activities, so any development and production activities will be subject
to their reasonable discretion. The success and timing of drilling and development activities on properties operated by the third-party
operators, therefore, depends on a number of factors that will be largely outside of the Sponsor’s control, including:
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the
timing and amount of capital expenditures, which could be significantly more than anticipated;
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the
availability of suitable drilling equipment, production and transportation infrastructure and qualified operating personnel;
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the
third-party operators’ expertise, operating efficiency and financial resources;
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approval
of other participants in drilling wells;
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the
selection of technology;
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the
selection of counterparties for the sale of production; and
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the
rate of production of the reserves.
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The
third-party operators may elect not to undertake development activities, or may undertake such activities in an unanticipated
fashion, which may result in significant fluctuations in capital expenditures and amounts available for distribution to Trust
unitholders.
The
bankruptcy of operators could impede the operation of wells.
The
value of the Net Profits Interest and the Trust’s ultimate cash available for distribution is highly dependent on the financial
condition of the operators of the wells. The ability to operate the Underlying Properties depends on all operators’ future
financial condition and economic performance and access to capital, which in turn will depend upon the supply and demand for oil
and natural gas, prevailing economic conditions and financial, business and other factors, many of which are beyond the control
of such operators. If the reduced demand for crude oil in the global market as a result of the economic effects of the COVID-19
pandemic persists for the near future or longer, such factors could have a negative impact on the financial condition and economic
performance of one or more of the operators of the Underlying Properties.
In
the event of any future bankruptcy of any operator of the Underlying Properties, the value of the Net Profits Interest could be
adversely affected by, among other things, delay or cessation of payments under the Net Profits Interest, business disruptions
or cessation of operations by the operator, replacements of operators, inability to find a replacement operator if necessary,
reduced production of reserves, or decreased distributions to Trust unitholders.
Developing
oil and natural gas wells and producing oil and natural gas are costly and high-risk activities with many uncertainties that could
adversely affect future production from the Underlying Properties. Any delays, reductions or cancellations in development and
producing activities could decrease revenues that are available for distribution to Trust unitholders.
The
process of developing oil and natural gas wells and producing oil and natural gas on the Underlying Properties is subject to numerous
risks beyond the Trust’s, the Sponsor’s and the third party operators’ control, including risks that could delay
the operators’ current drilling or production schedule and the risk that drilling will not result in commercially viable
oil or natural gas production. The ability of the operators to carry out operations or to finance planned development expenses
could be materially and adversely affected by any factor that may curtail, delay, reduce or cancel development and production,
including:
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reductions
in oil or natural gas prices;
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delays
imposed by or resulting from compliance with regulatory requirements, including permitting;
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unusual
or unexpected geological formations;
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shortages
of or delays in obtaining equipment and qualified personnel;
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lack
of available gathering facilities or delays in construction of gathering facilities;
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lack
of available capacity on interconnecting transmission pipelines;
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equipment
malfunctions, failures or accidents;
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unexpected
operational events and drilling conditions;
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market
limitations for oil or natural gas;
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pipe
or cement failures;
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lost
or damaged drilling and service tools;
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loss
of drilling fluid circulation;
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uncontrollable
flows of oil and natural gas, inert gas, water or drilling fluids;
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fires
and natural disasters;
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environmental
hazards, such as oil and natural gas leaks, pipeline ruptures and discharges of toxic gases;
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adverse
weather conditions; and
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oil
or natural gas property title problems.
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If planned operations, including drilling
of development wells, are delayed or cancelled, or if existing wells or development wells experience production below anticipated
levels due to one or more of the foregoing factors or for any other reason, estimated future distributions to Trust unitholders
may be reduced. If an operator incurs increased costs due to one or more of the foregoing factors or for any other reason and is
unable to recover such costs from insurance, estimated future distributions to Trust unitholders may be reduced.
Shortages of equipment, services and
qualified personnel could increase costs of developing and operating the Underlying Properties and result in a reduction in the
amount of cash available for distribution to the Trust unitholders.
The demand for qualified and experienced
personnel to conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas
industry can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Historically,
there have been shortages of drilling rigs and other equipment as demand for rigs and equipment has increased along with the number
of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher oil
and natural gas prices generally stimulate demand and result in increased prices for drilling rigs, crews and associated supplies,
equipment and services. Shortages of field personnel and equipment or price increases could hinder the ability of the operators
of the Underlying Properties to conduct the operations which they currently have planned for the Underlying Properties, which would
reduce the amount of cash received by the Trust and available for distribution to the Trust unitholders.
The generation of profits for distribution
by the Trust depends in part on access to and operation of gathering, transportation and processing facilities. Any limitation
in the availability of those facilities could interfere with sales of oil and natural gas production from the Underlying Properties.
The amount of oil and natural gas that may
be produced and sold from a well is subject to curtailment in certain circumstances, such as by reason of weather conditions, pipeline
interruptions due to scheduled and unscheduled maintenance, failure of tendered oil and natural gas to meet quality specifications
of gathering lines or downstream transporters, excessive line pressure which prevents delivery, physical damage to the gathering
system or transportation system or lack of contracted capacity on such systems. The curtailments may vary from a few days to several
months. In many cases, the operators of the Underlying Properties receive only limited notice, if any, as to when production will
be curtailed and the duration of such curtailments. If the operators of the Underlying Properties are forced to reduce production
due to such a curtailment, the revenues of the Trust and the amount of cash distributions to the Trust unitholders similarly would
be reduced due to the reduction of profits from the sale of production.
Adverse developments in Texas, Louisiana
or New Mexico could adversely impact the results of operations and cash flows of the Underlying Properties and reduce the amount
of cash available for distributions to Trust unitholders.
The operations of the Underlying Properties
are focused on the production and development of oil and natural gas within the states of Texas, Louisiana and New Mexico. As a
result, the results of operations and cash flows of the Underlying Properties depend upon continuing operations in these areas.
This concentration could disproportionately expose the Trust’s interests to operational and regulatory risk in these areas.
Due to the lack of diversification in geographic location, adverse developments in exploration and production of oil and natural
gas in any of these areas of operation could have a significantly greater impact on the results of operations and cash flows of
the Underlying Properties than if the operations were more diversified.
FINANCIAL RISKS
The Trust Units may lose value as
a result of title deficiencies with respect to the Underlying Properties.
Enduro acquired the Underlying Properties
through various acquisitions in late 2010 and early 2011. The Sponsor acquired Enduro’s interests in the Underlying Properties
pursuant to the Sale Transaction that closed in August 2018. The existence of a material title deficiency with respect to the
Underlying Properties could reduce the value of a property or render it worthless, thus adversely affecting the Net Profits Interest
and the distributions to Trust unitholders. The Sponsor does not obtain title insurance covering mineral leaseholds, and the Sponsor’s
failure to cure any title defects may cause the Sponsor to lose its rights to production from the Underlying Properties. If a
material title problem were to arise, profits available for distribution to Trust unitholders, and the value of the Trust Units,
may be reduced.
The reserves attributable to the Underlying
Properties are depleting assets and production from those reserves will diminish over time. Furthermore, the Trust is precluded
from acquiring other oil and natural gas properties or net profits interests to replace the depleting assets and production. Therefore,
proceeds to the Trust and cash distributions to Trust unitholders will decrease over time.
The profits payable to the Trust attributable
to the Net Profits Interest are derived from the sale of production of oil and natural gas from the Underlying Properties. The
reserves attributable to the Underlying Properties are depleting assets, which means that the reserves and the quantity of oil
and natural gas produced from the Underlying Properties will decline over time.
Future maintenance projects on the Underlying
Properties may affect the quantity of proved reserves that can be economically produced from wells on the Underlying Properties.
The timing and size of these projects will depend on, among other factors, the market prices of oil and natural gas. Neither the
Sponsor nor, to the Sponsor’s knowledge, the third-party operators have a contractual obligation to develop or otherwise
pay development expenses on the Underlying Properties in the future. Furthermore, with respect to properties for which the Sponsor
is not designated as the operator, the Sponsor has limited control over the timing or amount of those development expenses. The
Sponsor also has the right to non-consent and not participate in the development expenses on properties for which it is not the
operator, in which case the Sponsor and the Trust will not receive the production resulting from such development expenses. If
the operators of the Underlying Properties do not implement maintenance projects when warranted, the future rate of production
decline of proved reserves may be higher than the rate currently expected by the Sponsor or estimated in the reserve report.
The Trust Agreement provides that the Trust’s
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 related to the Net Profits Interest. As a result, the Trust is not permitted
to acquire other oil and natural gas properties or net profits interests to replace the depleting assets and production attributable
to the Net Profits Interest.
Because the net profits payable to the Trust
are derived from the sale of depleting assets, the portion of the distributions to Trust unitholders attributable to depletion
may be considered to have the effect of a return of capital as opposed to a return on investment. Eventually, the Underlying Properties
burdened by the Net Profits Interest may cease to produce in commercially paying quantities and the Trust may, therefore, cease
to receive any distributions of net profits therefrom. At that point the value of the Trust Units should be expected to be $0.
An increase in the differential between
the price realized by the Sponsor for oil or natural gas produced from the Underlying Properties and the NYMEX or other benchmark
price of oil or natural gas could reduce the profits to the Trust and, therefore, the cash distributions by the Trust and the value
of Trust Units.
The prices received for the Sponsor’s
oil and natural gas production usually fall below the relevant benchmark prices, such as NYMEX, that are used for calculating hedge
positions. The difference between the price received and the benchmark price is called a basis differential. The differential may
vary significantly due to market conditions, the quality and location of production and other factors. The Sponsor cannot accurately
predict oil or natural gas differentials. Increases in the differential between the realized price of oil and natural gas and the
benchmark price for oil and natural gas could reduce the profits to the Trust, the cash distributions by the Trust and the value
of the Trust Units.
The amount of cash available for distribution
by the Trust will be reduced by the amount of any costs and expenses related to the Underlying Properties and other costs and expenses
incurred by the Trust.
The Trust will indirectly bear an 80% share
of all costs and expenses related to the Underlying Properties, such as direct operating and development expenses, which will
reduce the amount of cash received by the Trust and thereafter distributable to Trust unitholders. Accordingly, higher costs and
expenses related to the Underlying Properties will directly decrease the amount of cash received by the Trust in respect of its
Net Profits Interest. Historical costs may not be indicative of future costs. For example, the third-party operators may in the
future propose additional drilling projects that significantly increase the capital expenditures associated with the Underlying
Properties, which could reduce cash available for distribution by the Trust. In addition, cash available for distribution by the
Trust will be further reduced by the Trust’s general and administrative expenses.
If direct operating and development expenses
on the Underlying Properties together with the other costs exceed gross profits of production from the Underlying Properties, the
Trust will not receive net profits from those properties until future gross profits from production exceed the total of the excess
costs, plus accrued interest at the prime rate. If the Trust does not receive net profits pursuant to the Net Profits Interest,
or if such net profits are reduced, the Trust will not be able to distribute cash to the Trust unitholders, or such cash distributions
will be reduced, respectively. Development activities may not generate sufficient additional revenue to repay the costs.
The amount of cash available for distribution
by the Trust could be reduced by expenses caused by uninsured claims.
The Sponsor maintains insurance coverage
against potential losses that it believes is customary in its industry. The Sponsor currently maintains general liability insurance
and excess liability coverage. The Sponsor’s excess liability coverage and general liability insurance do not have deductibles.
The general liability insurance covers the Sponsor and its subsidiaries for legal and contractual liabilities arising out of bodily
injury or property damage, including any resulting loss of use to third parties, and for sudden and accidental pollution or environmental
liability, while the excess liability coverage is in addition to and triggered if the general liability per occurrence limit is
reached. In addition, the Sponsor maintains control of well insurance with per occurrence limits depending on the status of the
well and deductibles consistent with industry standards. The Sponsor’s general liability insurance and excess liability policies
do not provide coverage with respect to legal and contractual liabilities of the Trust, and the Trust does not maintain such coverage
since it is passive in nature and does not have any ability to influence the Sponsor or control the operations or development of
the Underlying Properties. However, the Trust unitholders may indirectly benefit from the Sponsor’s insurance coverage to
the extent that insurance proceeds offset or reduce any costs or expenses that are deducted when calculating the net profits attributable
to the Trust.
The Sponsor does not currently have any
insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations;
however, the Sponsor believes its general liability and excess liability insurance policies would cover third-party claims related
to hydraulic fracturing operations in accordance with, and subject to, the terms of such policies. These policies may not cover
fines, penalties or costs and expenses related to government-mandated cleanup of pollution. In addition, these policies do not
provide coverage for all liabilities, and there can be no assurance that the insurance coverage will be adequate to cover claims
that may arise or that the Sponsor will be able to maintain adequate insurance at rates it considers reasonable. The occurrence
of an event not fully covered by insurance could result in a significant decrease in the amount of cash available for distribution
by the Trust. The Trust does not maintain any type of insurance against any of the risks of conducting oil and gas exploration
and production, hydraulic fracturing operations, or related activities.
The Sponsor’s ability to perform
its obligations to the Trust could be limited by restrictions under its debt agreements.
The Sponsor has various contractual obligations
to the Trust under the Trust Agreement and Conveyance. Restrictions under the Sponsor’s debt agreements, including
certain covenants, financial ratios and tests, could impair its ability to fulfill its obligations to the Trust. The requirement
that the Sponsor comply with these restrictive covenants and financial ratios and tests may materially adversely affect its ability
to react to changes in market conditions, take advantage of business opportunities it believes to be desirable, obtain future
financing, fund needed capital expenditures or withstand a continuing or future downturn in its business which may, in turn, impair
the Sponsor’s operations and its ability to perform its obligations to the Trust under the Trust Agreement and Conveyance.
If the Sponsor is unable to perform its obligations to the Trust under the Trust Agreement or Conveyance, it could have a material
adverse effect on the Trust.
The bankruptcy of the Sponsor or any
of the third-party operators could impede the operation of the wells and the development of the proved undeveloped reserves.
The value of the Net Profits Interest and
the Trust’s ultimate cash available for distribution will be highly dependent on the financial condition of the operators
of the Underlying Properties. None of the operators of the Underlying Properties, including the Sponsor, has agreed with the Trust
to maintain a certain net worth or to be restricted by other similar covenants.
The ability to develop and operate the Underlying
Properties depends on the future financial condition and economic performance and access to capital of the operators of those properties,
which in turn will depend upon the supply and demand for oil and natural gas, prevailing economic conditions and financial, business
and other factors, many of which are beyond the control of the Sponsor and the third party operators. The Sponsor is not a reporting
company and is not required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, Trust unitholders do
not have access to financial information about the Sponsor.
In the event of the bankruptcy of an operator
of the Underlying Properties, the working interest owners in the affected properties will have to seek a new party to perform the
development and the operations of the affected wells. The working interest owners may not be able to find a replacement driller
or operator, and they may not be able to enter into a new agreement with such replacement party on favorable terms within a reasonable
period. As a result, such a bankruptcy may result in reduced production from the reserves and decreased distributions to Trust
unitholders.
In the event of the bankruptcy of
the Sponsor, if a court were to hold that the Net Profits Interest was part of the bankruptcy estate, the Trust may be treated
as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana and New Mexico.
The Sponsor and the Trust believe that,
in a bankruptcy of the Sponsor, the Net Profits Interest would be viewed as a separate property interest under Texas law and, as
such, outside of the Sponsor’s bankruptcy estate. However, to the extent that were not the case, or to the extent Louisiana
or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy estate and
used to satisfy obligations to creditors of the Sponsor, in which case the Trust would be an unsecured creditor of the Sponsor
at risk of losing the entire value of the Net Profits Interest to senior creditors.
RISKS RELATED TO THE STRUCTURE OF THE TRUST
The Trust is passive in nature and
neither the Trust nor the Trust unitholders have any ability to influence the Sponsor or control the operations or development
of the Underlying Properties.
The Trust Units are a passive investment
that entitles the Trust unitholder to only receive cash distributions from the Net Profits Interest. Trust unitholders have no
voting rights with respect to the Sponsor and, therefore, have no managerial, contractual or other ability to influence the Sponsor’s
or the third-party operators’ activities or the operations of the Underlying Properties. Oil and natural gas properties are
typically managed pursuant to an operating agreement among the working interest owners of oil and natural gas properties. Third
party operators operate substantially all of the wells on the Underlying Properties. The typical operating agreement contains procedures
whereby the owners of the working interests in the property designate one of the interest owners to be the operator of the property.
Under these arrangements, the operator is typically responsible for making all decisions relating to drilling activities, sale
of production, compliance with regulatory requirements and other matters that affect the property.
The Sponsor may transfer all or a
portion of the Underlying Properties at any time without Trust unitholder consent, subject to specified limitations.
The Sponsor at any time may transfer all
or part of the Underlying Properties, subject to and burdened by the Net Profits Interest, and may, along with the third-party
operators, abandon individual wells or properties reasonably believed to be not economically viable. Trust unitholders will not
be entitled to vote on any transfer or abandonment of the Underlying Properties, and the Trust will not receive any profits from
any such transfer, except in the limited circumstances when the Net Profits Interest is released in connection with such transfer,
in which case the Trust will receive an amount equal to the fair market value (net of sales costs) of the Net Profits Interest
released. Following any sale or transfer of any of the Underlying Properties, if the Net Profits Interest is not released in connection
with such sale or transfer, the Net Profits Interest will continue to burden the transferred property and net profits attributable
to such property will be calculated as part of the computation of net profits. The Sponsor may delegate to the transferee responsibility
for all of the Sponsor’s obligations relating to the Net Profits Interest on the portion of the Underlying Properties transferred.
In addition, the Sponsor may, without the
consent of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with any lease that accounts
for 0.25% or less of the total production from the Underlying Properties in the prior 12 months and provided that the Net Profits
Interest covered by such releases cannot exceed, during any 12-month period, an aggregate fair market value to the Trust of $500,000.
These releases will be made only in connection with a sale by the Sponsor to a non-affiliate of the relevant Underlying Properties
and are conditioned upon an amount equal to the fair market value of such Net Profits Interest being treated as an offset amount
against costs and expenses. In January 2019, the Sponsor sold two producing wells and associated acreage of the Underlying
Properties under this provision for a sale price of approximately $62,000, and the Trustee released such properties from the Net
Profits Interest.
The third-party operators and the Sponsor
may enter into farm-out, operating, participation and other similar agreements to develop the property without the consent or approval
of the Trustee or any Trust unitholder.
Under certain circumstances, the Trustee
must sell the Net Profits Interest and dissolve the Trust prior to the expected termination of the Trust. As a result, Trust unitholders
may not recover their investment.
The Trustee must sell the Net Profits Interest
and dissolve the Trust if the holders of at least 75% of the outstanding Trust Units approve the sale or vote to dissolve the Trust.
The Trustee must also sell the Net Profits Interest and dissolve the Trust if 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 net profits of any such sale will
be distributed to the Trust unitholders.
Conflicts of interest could arise
between the Sponsor and its affiliates, on the one hand, and the Trust and the Trust unitholders, on the other hand.
As working interest owners in, and the operators
of certain wells on, the Underlying Properties, the Sponsor and its affiliates could have interests that conflict with the interests
of the Trust and the Trust unitholders. For example:
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The Sponsor’s interests may conflict with those
of the Trust and the Trust unitholders in situations involving the development, maintenance, operation or abandonment of certain
wells on the Underlying Properties for which the Sponsor acts as the operator. The Sponsor also may make decisions with respect
to development expenses that adversely affect the Underlying Properties. These decisions include reducing development expenses
on properties for which the Sponsor acts as the operator, which could cause oil and natural gas production to decline at a faster
rate and thereby result in lower cash distributions by the Trust in the future.
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The Sponsor may sell some or all the Underlying Properties
without taking into consideration the interests of the Trust unitholders. Such sales may not be in the best interests of the Trust
unitholders. These purchasers may lack the Sponsor’s experience or its creditworthiness. The Sponsor also has the right,
under certain circumstances, to cause the Trustee to release all or a portion of the Net Profits Interest in connection with a
sale of a portion of the Underlying Properties to which such Net Profits Interest relates. In such an event, the Trust is entitled
to receive the fair value (net of sales costs) of the Net Profits Interest released.
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The Sponsor may sell its Trust Units without considering
the effects such sale may have on Trust Unit prices or on the Trust itself. Additionally, the Sponsor can vote its Trust Units
in its sole discretion without considering the interests of the other Trust unitholders. The Sponsor is not a fiduciary with respect
to the Trust unitholders or the Trust and does not owe any fiduciary duties or liabilities to the Trust unitholders or the Trust.
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The Trust is administered by a Trustee
who cannot be replaced except by a majority vote of the Trust unitholders at a special meeting which may make it difficult for
Trust unitholders to remove or replace the Trustee.
The affairs of the Trust are administered
by the Trustee. The voting rights of a Trust unitholder are more limited than those of stockholders of most public corporations.
For example, there is no requirement for annual meetings of Trust unitholders or for an annual or other periodic re-election of
the Trustee. The Trust Agreement provides that the Trustee may only be removed and replaced by the holders of a majority of the
Trust Units present in person or by proxy at a meeting of such holders where a quorum is present, including Trust Units held by
the Sponsor, called by either the Trustee or the holders of not less than 10% of the outstanding Trust Units. As a result, it will
be difficult for public Trust unitholders to remove or replace the Trustee without the cooperation of holders of a significant
percentage of total Trust Units.
Trust unitholders have limited ability
to enforce provisions of the Net Profits Interest, and the Sponsor’s liability to the Trust is limited.
The Trust Agreement permits the Trustee
to sue the Sponsor or any other future owner of the Underlying Properties to enforce the terms of the Conveyance creating the Net
Profits Interest. If the Trustee does not take appropriate action to enforce provisions of the Conveyance, Trust unitholders’
recourse would be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. The Trust
Agreement expressly limits a Trust unitholder’s ability to directly sue the Sponsor or any other third party other than the
Trustee. As a result, Trust unitholders will not be able to sue the Sponsor or any future owner of the Underlying Properties to
enforce these rights. Furthermore, the Conveyance provides that, except as set forth in the Conveyance, the Sponsor will not be
liable to the Trust for the manner in which it performs its duties in operating the Underlying Properties as long as it acts without
gross negligence or willful misconduct.
RISKS RELATED TO OWNERSHIP OF THE TRUST UNITS
If the Trust cannot meet the New York
Stock Exchange continued listing requirements, the NYSE may delist the Trust units.
Under the continued listing requirements
of the NYSE, a company will be considered to be out of compliance with the exchange’s minimum price requirement if the company’s
average closing price over a consecutive 30 trading day period (“Average Closing Price”) is less than $1.00 (the “Minimum
Price Requirement”). Under NYSE rules, a company that is out of compliance with the Minimum Price Requirement has a
cure period of six months to regain compliance if it notifies the NYSE within 10 business days of receiving a deficiency notice
of its intention to cure the deficiency. A company may regain compliance if on the last trading day of any calendar month during
the cure period the company has a closing share price of at least $1.00 and an average closing share price of at least $1.00 over
the 30-trading-day period ending on the last trading day of that month. If at the expiration of the cure period, both a $1.00 closing
share price on the last trading day of the cure period and a $1.00 average closing share price over the 30-trading-day period ending
on the last trading day of the cure period are not attained, the NYSE will commence suspension and delisting procedures. If delisted
by the NYSE, a company’s shares may be transferred to the over-the-counter (“OTC”) market, a significantly more
limited market than the NYSE, which could affect the market price, trading volume, liquidity and resale price of such shares. Securities
that trade on the OTC markets also typically experience more volatility compared to securities that trade on a national securities
exchange. During the cure period, the company’s shares would continue to trade on the NYSE, subject to compliance with other
continued listing requirements.
On September 25, 2020, the Trust received
written notification from the NYSE that the Trust was not in compliance with the Minimum Price Requirement. Neither the Trust
nor the Trustee has any control over the trading price of the Trust units, nor does the Trust have the authority to cause a reverse
split of the units or to take similar action designed to affect the trading price of the units without a vote from the Trust unitholders.
Although the NYSE has notified the Trust that the Trust had regained compliance with the Minimum Price Requirement as of February
26, 2021, it might be unable to maintain compliance, and would again become subject to the NYSE delisting procedures.
The Sponsor may sell Trust Units in
the public or private markets, and such sales could have an adverse impact on the trading price of the Trust Units.
The Sponsor holds an aggregate of 8,600,000
Trust Units. The Sponsor may sell Trust Units in the public or private markets, and any such sales could have an adverse impact
on the price of the Trust Units. The Trust has granted registration rights to the Sponsor, which, if exercised, would facilitate
sales of Trust Units by the Sponsor.
The trading price for the Trust Units
may not reflect the value of the Net Profits Interest held by the Trust.
The trading price for publicly traded securities
similar to the Trust Units tends to be tied to recent and expected levels of cash distributions. The amounts available for distribution
by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for sales of oil
and natural gas production from the Underlying Properties and the timing and amount of direct operating expenses and development
expenses. Consequently, the market price for the Trust Units may not necessarily be indicative of the value that the Trust would
realize if it sold the Net Profits Interest to a third-party buyer. In addition, the market price may not necessarily reflect the
fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid with respect to the Trust
Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment.
As a result, distributions made to a Trust unitholder over the life of these depleting assets may not equal or exceed the purchase
price paid by the Trust unitholder.
Courts outside of Delaware may not
recognize the limited liability of the Trust unitholders provided under Delaware law.
Under the Delaware Statutory Trust Act,
Trust unitholders will be entitled to the same limitation of personal liability extended to stockholders of 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.
LEGAL, ENVIRONMENTAL AND REGULATORY RISKS
The operations of the Underlying Properties
are subject to environmental laws and regulations that could adversely affect the cost, manner or feasibility of conducting operations
on them or result in significant costs and liabilities, which could reduce the amount of cash available for distribution to Trust
unitholders.
The oil and natural gas exploration and
production operations on the Underlying Properties are subject to stringent and comprehensive federal, 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 numerous obligations that apply to the operations on the Underlying Properties, including the
requirement to obtain a permit before conducting drilling, waste disposal or other regulated activities; the restriction of types,
quantities and concentrations of materials that can be released into the environment; restrictions on water withdrawal and use;
the incurrence of significant development expenses to install pollution or safety-related controls at the operated facilities;
the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
and the imposition of substantial liabilities for pollution resulting from operations. For example, the EPA has published regulations
that impose more stringent emissions control requirements for oil and gas development and production operations, which may require
the Sponsor, its operators, or third-party contractors to incur additional expenses to control air emissions from current operations
and during new well developments by installing emissions control technologies and adhering to a variety of work practice and other
requirements. For example, in 2012 the EPA adopted federal New Source Performance Standards (“NSPS”) that require
the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion
operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.”
These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating
compressors, and from pneumatic controllers and storage vessels. In June 2016, the EPA published a final rule that requires
operators to reduce methane emissions from certain new, modified or reconstructed oil and gas facilities, including production,
processing, transmission and storage activities (“Methane Rule”). Following the 2016 presidential election and change
in administrations, the EPA convened a reconsideration proceeding that culminated in a 2020 rule proposal that eliminates the
obligation to control methane emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements
because they serve to control emissions of other pollutants. However, on January 20, 2021, President Biden issued an executive
order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding those 2020 amendments
to the Methane Rule by September 2021. That same order directs the EPA to propose new rules to establish standards of performance
and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector,
including the exploration and production, transmission, processing, and storage segments, by September 2021. The ultimate fate
of the Methane Rule and any related requirements for existing sources is unclear. Nevertheless, regulations promulgated under
the CAA may require the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work
practices to control emissions from its operations, which could reduce the profits available to the Trust and potentially impair
the economic development of the Underlying Properties. Numerous governmental authorities, such as the EPA and analogous state
agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring
difficult and costly actions. Failure to comply with these laws and regulations may result in the assessment of administrative,
civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting
or preventing some or all of the operations on the Underlying Properties. Furthermore, the inability to comply with environmental
laws and regulations in a cost-effective manner, such as removal and disposal of produced water and other generated oil and gas
wastes, could impair the operators’ ability to produce oil and natural gas commercially from the Underlying Properties,
which would reduce profits attributable to the Net Profits Interest.
There is inherent risk of incurring significant
environmental costs and liabilities in the operations on the Underlying Properties as a result of the handling of petroleum hydrocarbons
and wastes, air emissions and wastewater discharges related to operations, and historical industry operations and waste disposal
practices. Under certain environmental laws and regulations, the operators could be subject to joint and several strict liability
for the removal or remediation of previously released materials or property contamination regardless of whether such operators
were responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the
time those actions were taken. Private parties, including the owners of properties upon which wells are drilled and facilities
where petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to
enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury
or property damage. In addition, the risk of accidental spills or releases could expose the operators of the Underlying Properties
to significant liabilities that could have a material adverse effect on the operators’ businesses, financial condition and
results of operations and could reduce the amount of cash available for distribution to Trust unitholders. Changes in environmental
laws and regulations occur frequently, and any changes that result in more stringent or costly operational control requirements
or waste handling, storage, transport, disposal or cleanup requirements could require the operators of the Underlying Properties
to make significant expenditures to attain and maintain compliance and may otherwise have a material adverse effect on their results
of operations, competitive position or financial condition.
The Trust will indirectly bear 80% of all
costs and expenses paid by the Sponsor, including those related to environmental compliance and liabilities associated with the
Underlying Properties, including costs and liabilities resulting from conditions that existed prior to the Sponsor’s acquisition
of the Underlying Properties unless such costs and expenses result from the operator’s negligence or misconduct. In addition,
as a result of the increased cost of compliance, the operators of the Underlying Properties may decide to discontinue drilling.
Neither the Sponsor nor the Trust is generally
entitled to, nor required to provide, indemnity to third party operators with respect to pollution liability and associated environmental
remediation costs. However, the Sponsor may be required to provide, and may be entitled to, indemnity from third party operators
with respect to such liabilities and costs in the event of the other party’s gross negligence or misconduct. In addition,
the Sponsor has agreed to assume certain environmental liabilities of prior owners of the Underlying Properties in connection
with the purchase thereof.
The operations on the Underlying Properties
are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility
of conducting operations on them or expose the operator to significant liabilities, which could reduce the amount of cash available
for distribution to Trust unitholders.
The production and development operations
on the Underlying Properties are subject to complex and stringent laws and regulations. To conduct their operations in compliance
with these laws and regulations, the operators of the Underlying Properties must obtain and maintain numerous permits, drilling
bonds, approvals and certificates from various federal, state and local governmental authorities and engage in extensive reporting.
The operators of the Underlying Properties may incur substantial costs and experience delays in order to maintain compliance with
these existing laws and regulations, and the Trust will bear an 80% share of these costs. In addition, the operators’ costs
of compliance may increase if existing laws and regulations are revised or reinterpreted, or if new laws and regulations become
applicable to their operations. Such costs could have a material adverse effect on the operators’ business, financial condition
and results of operations and reduce the amount of cash received by the Trust in respect of the Net Profits Interest. The operators
of the Underlying Properties must also comply with laws and regulations prohibiting fraud and market manipulations in energy markets.
To the extent the operators of the Underlying Properties are shippers on interstate pipelines, they must comply with the tariffs
of such pipelines and with federal policies related to the use of interstate capacity, and such compliance costs will be borne
in part by the Trust.
Laws and regulations governing exploration
and production may also affect production levels. The operators of the Underlying Properties are required to comply with federal
and state laws and regulations governing conservation matters, including: provisions related to the unitization or pooling of the
oil and natural gas properties; the establishment of maximum rates of production from wells; the spacing of wells; the plugging
and abandonment of wells; and the removal of related production equipment. Additionally, state and federal regulatory authorities
may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increase capital costs on
the part of the operators and third party downstream natural gas transporters. These and other laws and regulations can limit the
amount of oil and natural gas the operators can produce from their wells, limit the number of wells they can drill, or limit the
locations at which they can conduct drilling operations, which in turn could negatively impact Trust distributions, estimated and
actual future net revenues to the Trust and estimates of reserves attributable to the Trust’s interests.
New laws or regulations, or changes to existing
laws or regulations, may unfavorably impact the operators of the Underlying Properties and result in increased operating costs
or have a material adverse effect on their financial condition and results of operations and reduce the amount of cash received
by the Trust. For example, Congress is currently considering legislation that, if adopted in its proposed form, would subject companies
involved in oil and natural gas exploration and production activities to, among other items, additional regulation of and restrictions
on hydraulic fracturing of wells, the elimination of certain U.S. federal tax incentives and deductions available to oil and natural
gas exploration and production activities and the prohibition or additional regulation of private energy commodity derivative and
hedging activities. These and other potential regulations could increase the operating costs of the Underlying Properties, reduce
the operators’ liquidity, delay the operators’ operations or otherwise alter the way the operators conduct their business,
any of which could have a material adverse effect on the Trust and the amount of cash available for distribution to Trust unitholders.
Climate change laws and regulations
restricting emissions of “greenhouse gases” could result in increased operating costs and reduced demand for the oil
and natural gas that the operators produce while the physical effects of climate change could disrupt their production and cause
them to incur significant costs in preparing for or responding to those effects.
The oil and gas industry is a direct source
of certain greenhouse gas (“GHG”) emissions, namely carbon dioxide and methane, and future restrictions on such emissions
could impact future operations on the Underlying Properties. In December 2009, the EPA published its findings that emissions
of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment because emissions of such
gases are contributing to the warming of the Earth’s atmosphere and other climate changes. Based on these findings, the
agency has begun adopting and implementing regulations that would restrict emissions of GHGs under existing provisions of the
federal Clean Air Act. The EPA has adopted rules that regulate emissions of GHGs from certain large stationary sources under the
Prevention of Significant Deterioration (“PSD”) and Title V operating permit reviews for GHG emissions from certain
large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. Facilities
required to obtain PSD permits for their GHG emissions also will be required to meet “best available control technology”
standards that typically are established by the states.
In June 2014, the U.S. Supreme Court held
that GHG alone cannot trigger an obligation to obtain an air permit. However, the Supreme Court upheld EPA’s authority to
regulate GHG emissions from stationary sources, concluding sources that trigger air permitting requirements based on their traditional
criteria pollutant emissions must include a limit for GHG in their permit. These EPA rules could affect the operations on the Underlying
Properties or the ability of the operators of the Underlying Properties to obtain air permits for new or modified facilities.
In June 2016, the EPA published the Methane
Rule. Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding that
that culminated in a 2020 rule that eliminated the obligation to control methane emissions under the NSPS, while maintaining the
rule’s substantive emissions control requirements because they serve to control emissions of other pollutants. However, on
January 20, 2021, President Biden issued an executive order calling on the EPA to, among other things, consider a proposed rule
suspending, revising or rescinding those 2020 amendments to the Methane Rule by September 2021. That same order directs the EPA
to propose new rules to establish standards of performance and emission guidelines for methane and volatile organic compound emissions
from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage
segments, by September 2021. The ultimate fate of the Methane Rule and any related requirements for existing sources is unclear.
Nevertheless, regulations promulgated under the CAA may require the Sponsor to incur development expenses to install and utilize
specific equipment, technologies, or work practices to control emissions from its operations.
In addition, in November 2016, the U.S.
Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting,
flaring, and leaks during oil and gas operations on federal and tribal lands that are substantially similar to the EPA’s
Methane Rule. However, on December 8, 2017, the BLM published a final rule to temporarily suspend or delay certain requirements
contained in the November 2016 final rule until January 2019, including those requirements relating to venting, flaring and leakage
from oil and gas production activities. Further, in September 2018, the BLM published a final rule to revise or rescind certain
provisions of the 2016 rule. While the future implementation of the EPA and BLM rules aimed at controlling GHG emissions from oil
and natural gas sources remains uncertain, future federal GHG regulations for the oil and gas industry remain a possibility given
the long-term trend towards increasing regulation, and the Underlying Properties may be subject to these requirements or become
subject to them in the future.
More than one-third of the states have begun
taking actions to control and/or reduce emissions of GHGs, primarily through the planned development of GHG emission inventories
and/or regional GHG cap and trade programs. Although most of the state-level initiatives have to date focused on large sources
of GHG emissions, such as coal-fired electric plants, it is possible that smaller sources of emissions could become subject to
GHG emission limitations or allowance purchase requirements in the future. In addition, from time to time Congress has considered
adopting legislation to reduce emissions of greenhouse gases. Any one of these climate change regulatory and legislative initiatives
could have a material adverse effect on the Sponsor’s business, capital expenditures, financial condition and results of
operations.
At the international level, the U.S. joined
the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change
in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission
reduction goals every five years beginning in 2020. While the Agreement did not impose direct requirements on emitters, national
plans to meet its pledge could have resulted in new regulatory requirements. In November 2019, however, plans were formally announced
for the U.S. to withdraw from the Paris Agreement, and the U.S.’s withdrawal from the Paris Agreement took effect on November
4, 2020. On January 20, 2021, President Biden issued an executive order commencing the process to reenter the Paris Agreement,
although the emissions pledges in connection with that effort have not yet been updated. The U.S. formally rejoined the Paris
Agreement in February 2021. The Trust cannot predict whether re-entry into the Paris Agreement or pledges made in connection therewith
will result in new regulatory requirements or whether such requirements will cause the Sponsor to incur material costs.
In a separate executive order issued on
January 20, 2021, President Biden asked the heads of all executive departments and agencies to review and take action to address
any Federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration
that may be inconsistent with or present obstacles to the administration’s stated goals of protecting public health and the
environment, and conserving national monuments and refuges. Regulations specifically mentioned for review and possible suspension,
revision or rescission include the Methane Rule, and the EPA was ordered to, among other things, propose new regulations to establish
comprehensive standards for performance and emission guidelines for methane from existing oil and gas operations by September 2021.
The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which is called on to,
among other things, capture the full costs of greenhouse gas emissions, including the “social cost of carbon,” “social
cost of nitrous oxide” and “social cost of methane,” which are “the monetized damages associated with incremental
increased in greenhouse gas emissions,” including “changes in net agricultural productivity, human health, property
damage from increased flood risk, and the value of ecosystem services.”
The adoption and implementation of regulations
imposing reporting obligations on, or limiting emissions of GHGs from, the Sponsor’s equipment and operations could require
the Sponsor to incur costs to reduce emissions of GHGs associated with its operations or could adversely affect demand for the
natural gas it produces. Legislation or regulations that may be adopted to address climate change could also affect the markets
for the Sponsor’s products by making its products more or less desirable than competing sources of energy. To the extent
that its products are competing with higher GHG-emitting energy sources, the Sponsor’s products may become more desirable
in the market with more stringent limitations on GHG emissions. To the extent that its products are competing with lower GHG-emitting
energy, the Sponsor’s products may become less desirable in the market with more stringent limitations on greenhouse gas
emissions. The Sponsor cannot predict with any certainty at this time how these possibilities may affect its operations.
Because regulation of GHG emissions is relatively
new, further regulatory, legislative and judicial developments are likely to occur. Such developments may affect how these GHG
initiatives will impact the operators of the Underlying Properties and the Trust.
Finally, some scientists have concluded
that increasing concentrations of greenhouse gases in the Earth’s atmosphere may produce climate changes that have significant
physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events. If any such
effects were to occur, they could have an adverse effect on the operators’ assets and operations and, consequently, may reduce
profits attributable to the Net Profits Interest and, as a result, the Trust’s cash available for distribution. Additionally,
energy needs could increase or decrease as a result of extreme weather conditions, depending on the duration and magnitude of those
conditions.
Federal and state legislative and
regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or
delays as well as adversely affect the services of the operators of the Underlying Properties.
Hydraulic fracturing is an important and
common practice that is used to stimulate production of hydrocarbons from tight formations. The process involves the injection
of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process
is typically regulated by state oil and gas commissions. However, the EPA has asserted federal regulatory authority over hydraulic
fracturing. 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 2012 the EPA adopted federal NSPS that
require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which
well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green
completions.” These regulations also establish specific new requirements regarding emissions from production-related wet
seal and reciprocating compressors, and from pneumatic controllers and storage vessels. In June 2016, the EPA published the
Methane Rule. Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding
that culminated in a 2019 rule proposal that would eliminate the obligation to control methane emissions under the NSPS, while
maintaining the rule’s substantive emissions control requirements because they serve to control emissions of other pollutants.
The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require
the Sponsor to incur development expenses to install and utilize specific equipment, technologies, or work practices to control
emissions from its operations, which could reduce the profits available to the Trust and potentially impair the economic development
of the Underlying Properties.
Some states have adopted, and other states
are considering adopting, regulations that could restrict or impose additional requirements relating to hydraulic fracturing in
certain circumstances, including the disclosure of information regarding the substances used in the hydraulic fracturing process.
Such federal or state legislation could require the disclosure of chemical constituents used in the fracturing process to state
or federal regulatory authorities who could then make such information publicly available. Disclosure of chemicals used in the
fracturing process could make it easier for third parties opposing hydraulic fracturing to initiate legal proceedings against producers
and service providers based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater.
In addition, if hydraulic fracturing is regulated at the federal level, the Sponsor’s and the third party operators’
fracturing activities could become subject to additional permit requirements or operational restrictions and also to associated
permitting delays and potential increases in costs. In December 2014, the Governor of New York announced that the state would maintain
its moratorium on hydraulic fracturing in the state. Further, some local governments, including in Texas, have imposed moratoria
on drilling permits within city limits so that local ordinances may be reviewed to assess their adequacy to address such activities.
Similar measures might be considered or implemented in the jurisdictions in which the Underlying Properties are located.
If new laws or regulations that significantly
restrict or otherwise impact hydraulic fracturing are passed by Congress or adopted in Texas, Louisiana or New Mexico, such legal
requirements could make it more difficult or costly for the Sponsor or the third party operators to perform hydraulic fracturing
activities and thereby could affect the determination of whether a well is commercially viable. In addition, restrictions on hydraulic
fracturing could reduce the amount of oil and natural gas that the operators are ultimately able to produce in commercially paying
quantities from the Underlying Properties, and could increase the cycle times and costs to receive permits, delay or possibly preclude
receipt of permits in certain areas, impact water usage and waste water disposal and require air emissions, water usage and chemical
additives disclosures.
CYBERSECURITY RISKS
Cyber-attacks or
other failures in telecommunications or information technology systems could result in information theft, data corruption and significant
disruption of the Sponsor’s business operations.
In recent years, the Sponsor
has increasingly relied on information technology (“IT”) systems and networks in connection with its business activities,
including certain of its exploration, development and production activities. the Sponsor relies on digital technology, including
information systems and related infrastructure, as well as cloud applications and services, to, among other things, estimate quantities
of oil and natural gas reserves, analyze seismic and drilling information, process and record financial and operating data and
communicate with employees and third parties. As dependence on digital technologies has increased, cyber incidents, including deliberate
attacks and attempts to gain unauthorized access to computer systems and networks, have increased in frequency and sophistication.
These threats pose a risk to the security of the Sponsor’s systems and networks, the confidentiality, availability and integrity
of its data and the physical security of its employees and assets. Any cyber-attack could have a material adverse effect on the
Sponsor’s reputation, competitive position, business, financial condition and results of operations, and could have a material
adverse effect on the Trust. Cyber-attacks or security breaches also could result in litigation or regulatory action, as well as
significant additional expense to the Sponsor to implement further data protection measures.
In addition to the risks
presented to the Sponsor’s systems and networks, cyber-attacks affecting oil and natural gas distribution systems maintained
by third parties, or the networks and infrastructure on which they rely, could delay or prevent delivery to markets. A cyber-attack
of this nature would be outside the Sponsor’s ability to control, but could have a material adverse effect on the Sponsor’s
business, financial condition and results of operations, and could have a material adverse effect on the Trust.
Cyber-attacks or
other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption
of the Trustee’s operations.
The Trustee depends heavily
upon IT systems and networks in connection with its business activities. Despite a variety of security measures implemented by
the Trustee, events such as the loss or theft of back-up tapes or other data storage media could occur, and the Trustee’s
computer systems could be subject to physical and electronic break-ins, cyber-attacks and similar disruptions from unauthorized
tampering, including threats that may come from external factors, such as governments, organized crime, hackers and third parties
to whom certain functions are outsourced, or may originate internally from within the respective companies.
If a cyber-attack were to occur, it could
potentially jeopardize the confidential, proprietary and other information processed and stored in, and transmitted through, the
Trustee’s computer systems and networks, or otherwise cause interruptions or malfunctions in the operations of the Trust,
which could result in litigation, increased costs and regulatory penalties. Although steps are taken to prevent and detect such
attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure
to these consequences.
TAX RISKS RELATED TO THE TRUST UNITS
The Trust has not requested a ruling
from the IRS regarding the tax treatment of the Trust. If the IRS were to determine (and be sustained in that determination) that
the Trust is not a “grantor trust” for U.S. federal income tax purposes, the Trust could be subject to more complex
and costly tax reporting requirements that could reduce the amount of cash available for distribution to Trust unitholders.
If the Trust were not treated as a grantor
trust for U.S. federal income tax purposes, the Trust should be treated as a partnership for such purposes. Although the Trust
would not become subject to U.S. federal income taxation at the entity level as a result of treatment as a partnership, and items
of income, gain, loss and deduction would flow through to the Trust unitholders, the Trust’s tax reporting requirements would
be more complex and costly to implement and maintain, and its distributions to Trust unitholders could be reduced as a result.
If the Trust were treated for U.S. federal
income tax purposes as a partnership, it likely would be subject to new audit procedures that for taxable years beginning after
December 31, 2017, alter the procedures for auditing large partnerships and also alter the procedures for assessing and collecting
income taxes due (including applicable penalties and interest) as a result of an audit. These rules effectively would impose an
entity level tax on the Trust, and unitholders may have to bear the expense of the adjustment even if they were not Trust unitholders
during the audited taxable year.
Neither the Sponsor nor the Trustee has
requested a ruling from the IRS regarding the tax status of the Trust, and neither the Sponsor nor the Trust can provide any assurance
that such a ruling would be granted if requested or that the IRS will not challenge these positions on audit.
Trust unitholders should be aware of the
possible state tax implications of owning Trust Units.
Unitholders are required to pay taxes
on their share of the Trust’s income even if they do not receive any cash distributions from the Trust.
Trust unitholders are treated as if they
own the Trust’s assets and receive the Trust’s income and are directly taxable thereon as if no Trust were in existence.
Because the Trust generates taxable income that could be different in amount than the cash the Trust distributes, unitholders
are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of the Trust’s
taxable income even if they receive no cash distributions from the Trust. A unitholder may not receive cash distributions from
the Trust equal to such unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability
that results from that income.
A portion of any tax gain on the disposition
of the Trust Units could be taxed as ordinary income.
If a unitholder sells Trust Units, he or
she will recognize a gain or loss equal to the difference between the amount realized and his or her tax basis in those Trust Units.
A substantial portion of any gain recognized may be taxed as ordinary income due to potential recapture items, including depletion
recapture.
The Trust allocates its items of income,
gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership of the Trust
Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. The IRS may challenge
this treatment, which could change the allocation of items of income, gain, loss and deduction among the Trust unitholders.
The Trust generally allocates its items
of income, gain, loss and deduction between transferors and transferees of the Trust Units each month based upon the ownership
of the Trust Units on the monthly record date, instead of on the basis of the date a particular Trust Unit is transferred. It is
possible that the IRS could disagree with this allocation method and could 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 Trust unitholders
affected by the issue and result in an increase in the administrative expense of the Trust in subsequent periods.
Trust unitholders should consult their
tax advisors as to the specific tax consequences of the ownership and disposition of the of the Trust Units, including the applicability
and effect of U.S. federal, state, local, and foreign income and other tax laws in light of their particular circumstances.
|
Item 1B.
|
Unresolved Staff Comments.
|
None.
Description of the Underlying Properties
The Underlying Properties consist of producing
and non-producing interests in oil and natural gas units, wells and lands in Texas, Louisiana and New Mexico. The Underlying Properties
include a portion of the assets in east Texas and north Louisiana acquired by Enduro from Denbury Resources Inc. in December 2010,
and all of the assets in the Permian Basin of New Mexico and west Texas acquired by Enduro from Samson Investment Company and ConocoPhillips
Company in January 2011 and February 2011, respectively. In August 2018, the Sponsor purchased the Underlying Properties from Enduro
and assumed all of Enduro’s obligations under the Trust Agreement and other instruments to which Enduro and the Trustee were
parties. The Underlying Properties are divided into two geographic regions: the Permian Basin region and East Texas/North Louisiana
region.
As of December 31, 2020, the Underlying
Properties had proved reserves of 12.2 MMBoe with 83% and 96% of the volumes and PV-10 value, respectively, attributable to proved
developed reserves. Substantially all of the 12.2 MMBoe of proved reserves, based on PV-10 value, were operated by third-party
operators.
The Sponsor’s interests in the Underlying
Properties require the Sponsor to bear its proportionate share of the costs of development and operation of such properties. As
of December 31, 2020, the Sponsor held average working interests of approximately 25% and 18% and average net revenue interests
of approximately 21% and 13% in the Underlying Properties located in the Permian Basin and East Texas/North Louisiana regions,
respectively. The Underlying Properties are also burdened by non-cost bearing interests owned by third parties consisting primarily
of overriding royalty and royalty interests.
Reserves
Cawley, Gillespie & Associates, Inc.
(“Cawley Gillespie”), independent petroleum and geological engineers, estimated crude oil (including natural gas liquids)
and natural gas proved reserves of the Underlying Properties’ full economic life and for the Trust life as of December 31,
2020. Numerous uncertainties are inherent in estimating reserve volumes and values, and the estimates are subject to change as
additional information becomes available. The reserves actually recovered and the timing of production of the reserves may vary
significantly from the original estimates. In addition, the reserves and net revenues attributable to the Net Profits Interest
include only 80% of the reserves attributable to the Underlying Properties that are expected to be produced within the term of
the Net Profits Interest.
The independent petroleum engineer’s
report as to the proved oil and natural gas reserves as of December 31, 2020 was prepared by Cawley Gillespie. Cawley Gillespie,
whose firm registration number is F-693, was founded in 1961 and is a leader in the evaluation of oil and gas properties. The technical
person at Cawley Gillespie primarily responsible for overseeing the reserve estimates with respect to the Underlying Properties
and the Net Profits Interest attributable to the Trust is W. Todd Brooker. Mr. Brooker has been a petroleum consultant for
Cawley Gillespie since 1992 and is currently the Senior Vice President. He is a registered professional engineer in the State of
Texas (license no. 83462) and a graduate of the University of Texas with a Bachelor of Science in Petroleum Engineering.
Information concerning changes in net proved
reserves attributable to the Trust, and the calculation of the standardized measure of the related discounted future net revenues
is contained in the notes to the financial statements of the Trust included in this Form 10-K. The Sponsor has not filed reserve
estimates covering the Underlying Properties with any other federal authority or agency.
The following table summarizes the estimated
proved reserve quantities and PV-10 attributable to the Trust and Underlying Properties as of December 31, 2020 and 2019:
|
|
Trust Net Profits Interest
|
|
|
Underlying Properties
|
|
|
|
Oil(1)
|
|
|
Natural
Gas
|
|
|
Total(2)
|
|
|
PV-10(3)
|
|
|
Oil(1)
|
|
|
Natural
Gas
|
|
|
Total(2)
|
|
|
PV-10(3)
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(in thousands)
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
|
(in thousands)
|
|
2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
|
2,196
|
|
|
|
5,404
|
|
|
|
3,097
|
|
|
$
|
28,598
|
|
|
|
6,995
|
|
|
|
17,117
|
|
|
|
9,848
|
|
|
$
|
35,747
|
|
Proved Developed Non-Producing
|
|
|
8
|
|
|
|
898
|
|
|
|
158
|
|
|
|
973
|
|
|
|
15
|
|
|
|
1,540
|
|
|
|
271
|
|
|
|
1,019
|
|
Proved Undeveloped
|
|
|
2
|
|
|
|
4,552
|
|
|
|
761
|
|
|
|
2,818
|
|
|
|
5
|
|
|
|
12,271
|
|
|
|
2,050
|
|
|
|
1,693
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved Developed Producing
|
|
|
2,878
|
|
|
|
6,149
|
|
|
|
3,903
|
|
|
$
|
62,184
|
|
|
|
10,020
|
|
|
|
20,960
|
|
|
|
13,513
|
|
|
$
|
77,730
|
|
Proved Developed Non-Producing
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Proved Undeveloped
|
|
|
243
|
|
|
|
8,184
|
|
|
|
1,607
|
|
|
|
10,968
|
|
|
|
613
|
|
|
|
16,865
|
|
|
|
3,424
|
|
|
|
7,374
|
|
(1)
|
Reserves for natural gas liquids are immaterial and included as a component of oil reserves.
|
(2)
|
Boe represents an approximate energy equivalent basis such that one Bbl of crude oil equals approximately six Mcf of natural
gas. However, the value of oil and natural gas value and the value of reserve volumes of oil and natural gas are often substantially
different than the amount implied by the Boe ratio.
|
(3)
|
PV-10 is a non-GAAP financial measure and represents the present value of estimated future cash inflows from proved crude oil
and natural gas reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future
cash inflows using the twelve-month unweighted arithmetic average of the first-day-of-the-month commodity prices, after adjustment
for differentials in location and quality, for each of the preceding twelve months. An estimate of PV-10 is provided because it
provides useful information to investors as it is widely used by professional analysts and sophisticated investors when evaluating
oil and gas companies. PV-10 is considered relevant and useful for evaluating the relative monetary significance of oil and natural
gas reserves. PV-10 is not intended to represent the current market value of the estimated reserves of the Underlying Properties.
PV-10 differs from standardized measure of discounted future net cash flows because it does not include the effect of future income
taxes. Please refer to the notes to the financial statements of the Trust included in this Form 10-K.
|
Reserve quantities and revenues for the
Net Profits Interest were estimated from projections of reserves and revenues attributable to the Underlying Properties. Since
the Trust has a defined Net Profits Interest, the Trust does not own a specific percentage of the oil and natural gas reserve quantities.
Accordingly, reserves allocated to the Trust pertaining to its 80% Net Profits Interest in the Underlying Properties have effectively
been reduced to reflect recovery of the Trust’s 80% portion of applicable production and development costs. Because Trust
reserve quantities are determined using an allocation formula, any changes in actual or assumed prices or costs will result in
revisions to the estimated reserve quantities allocated to the Net Profits Interest.
Estimates of proved reserves were prepared
in accordance with guidelines prescribed by the SEC and the Financial Accounting Standards Board, which require that reserve estimates
be prepared under existing economic and operating conditions based upon an average of the NYMEX first-day-of-the-month commodity
price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual
arrangements. Prices used in estimating reserves were as follows:
|
|
2020
|
|
|
2019
|
|
|
2018
|
|
Oil (per Bbl)
|
|
$
|
39.57
|
|
|
$
|
55.69
|
|
|
$
|
65.56
|
|
Natural gas (per MMBTU)
|
|
$
|
1.99
|
|
|
$
|
2.58
|
|
|
$
|
3.10
|
|
Changes in Proved Undeveloped Reserves
During the year ended December 31, 2020,
proved undeveloped reserves of the Underlying Properties decreased 1.4 MMBoe due to decrease in the amount of booked, non-operated
Wolfcamp shale wells in the Permian Basin, partially offset by modest increases in the estimated reserves for the booked, non-operated
wells in Haynesville shale of Louisiana. Compared to the year ended December 31, 2019, a decreased amount of proved undeveloped
gross wells were recognized in the reserves of the Underlying Properties when compared to the year ended December 31, 2020. The
decrease in gross wells does not represent a reduction in undeveloped reserves potential, as these reserves are still part of the
Underlying Properties. However, the reduction was estimated based on an updated market view of third-party operators’ completion
activity given current oil price volatility. The following is a summary of the changes in quantities of proved undeveloped reserves
for the Underlying Properties during the year ended December 31, 2020.
|
|
Underlying Properties
|
|
|
|
Oil(1)
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
(MBbls)
|
|
|
(MMcf)
|
|
|
(MBoe)
|
|
Balance – December 31, 2019
|
|
|
613
|
|
|
|
16,865
|
|
|
|
3,424
|
|
Development
|
|
|
5
|
|
|
|
6
|
|
|
|
5
|
|
Revisions and Other
|
|
|
(613
|
)
|
|
|
(4,600
|
)
|
|
|
(1,379
|
)
|
Balance – December 31, 2020
|
|
|
5
|
|
|
|
12,271
|
|
|
|
2,050
|
|
|
(1)
|
Reserves for natural gas liquids are immaterial and included
as a component of oil reserves.
|
Producing Acreage and Well Counts
For the following data, “gross”
refers to the total number of wells or acres in the Underlying Properties and “net” refers to gross wells or acres
multiplied by the percentage working interest owned by the Sponsor and in turn attributable to the Underlying Properties. All of
the acreage comprising the Underlying Properties is held by production. Although many wells produce both oil and natural gas, a
well is categorized as an oil well or a natural gas well based upon the ratio of oil to natural gas production.
The Underlying Properties are interests
in properties located in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region. The following
is a summary of the approximate acreage of the Underlying Properties at December 31, 2020:
|
|
Acres
|
|
|
|
Gross
|
|
|
Net
|
|
Permian Basin
|
|
|
123,637
|
|
|
|
36,580
|
|
East Texas/North Louisiana
|
|
|
12,629
|
|
|
|
4,899
|
|
Total
|
|
|
135,266
|
|
|
|
41,479
|
|
The following is a summary of the producing
wells on the Underlying Properties as of December 31, 2020:
|
|
Oil
|
|
|
Natural Gas
|
|
|
|
Gross Wells(1)
|
|
|
Net Wells
|
|
|
Gross Wells(1)
|
|
|
Net Wells
|
|
Permian Basin
|
|
|
3,023
|
|
|
|
290
|
|
|
|
71
|
|
|
|
26
|
|
East Texas/North Louisiana
|
|
|
—
|
|
|
|
—
|
|
|
|
318
|
|
|
|
54
|
|
Total
|
|
|
3,023
|
|
|
|
290
|
|
|
|
389
|
|
|
|
80
|
|
|
(1)
|
The Sponsor’s total producing wells include 17
operated wells and 3,395 non-operated wells.
|
The following is a summary of the number
of development and exploratory wells drilled on the Underlying Properties located in the Permian Basin and East Texas/North Louisiana
during the last three years:
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
|
2019
|
|
|
2018
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
Permian Basin
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
0.1
|
|
|
|
6
|
|
|
|
0.5
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
0.1
|
|
|
|
6
|
|
|
|
0.5
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
0.1
|
|
|
|
6
|
|
|
|
0.5
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
2
|
|
|
|
0.1
|
|
|
|
6
|
|
|
|
0.5
|
|
|
|
Year Ended December 31,
|
|
|
|
2020
|
|
|
2019
|
|
|
2018
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
East Texas/North Louisiana
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development Wells: (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
3
|
|
|
|
0.1
|
|
|
|
—
|
|
|
|
—
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3
|
|
|
|
0.1
|
|
|
|
—
|
|
|
|
—
|
|
Exploratory Wells:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Total:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Productive
|
|
|
—
|
|
|
|
—
|
|
|
|
3
|
|
|
|
0.1
|
|
|
|
—
|
|
|
|
—
|
|
Dry holes
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
—
|
|
|
|
—
|
|
|
|
3
|
|
|
|
0.1
|
|
|
|
—
|
|
|
|
—
|
|
|
(1)
|
Production of natural gas liquids is immaterial and included
as a component of natural gas production.
|
Major Producing Areas
Substantially all of the Underlying Properties
are located in mature oil fields that are characterized by long production histories. Based on the reserve reports, approximately
58% of the future production from the Underlying Properties is expected to be oil and approximately 42% is expected to be natural
gas.
Permian Basin Region
The Permian Basin is one of the largest
and most prolific oil and natural gas producing basins in the United States. The Underlying Properties in the Permian Basin contain
123,637 gross (36,580 net) acres in Texas and New Mexico.
The largest fields in the Underlying Properties
are located primarily in the Permian Basin (measured by Boe reserves at December 31, 2020). The largest field in the Permian Basin
region is the Lost Tank field, which individually accounts for more than 15 percent of the Underlying Properties reserves as of
December 31, 2020. This unit produces from the Brushy Canyon and Wolfcamp formations at depths up to 8,500 feet. Proved reserves
attributable to the Underlying Properties in the Lost Tank field were 2.6 MMBoe as of December 31, 2020. This field is
operated by Occidental Petroleum.
East Texas/North Louisiana Region
The Underlying Properties contain interests
in 12,629 gross (4,899 net) acres in the East Texas/North Louisiana region across three fields: the Elm Grove field, operated primarily
by Aethon Energy Operating, LLC and Comstock Oil & Gas, LLC; the Kingston field, operated by EXCO Resources and Indigo Resources,
LLC; and the Stockman field, operated by COERT. Substantially all proved reserves attributable to the Underlying Properties in
the East Texas/North Louisiana region are located in the Haynesville, Cotton Valley, and Hosston reservoirs of the Elm Grove and
Kingston fields. Proved reserves attributable to the Underlying Properties in the Elm Grove and Kingston fields were 2.3 MMBoe
and 0.1 MMBoe, respectively, as of December 31, 2020.
Production and Reserves
The following table shows the net production,
average sales price, average lease operating expense, and proved reserves as of year-end for the Underlying Properties located
in the Permian Basin of west Texas and New Mexico and in the East Texas/North Louisiana region, which relates to the amounts included
in the net profits calculation for the distributions paid during the years ended December 31, 2020, 2019 and 2018.
|
|
|
|
Year Ended December 31,
|
|
|
|
|
|
2020
|
|
|
2019
|
|
|
2018
|
|
Permian Basin
|
|
Oil Sales Volumes (Bbls)
|
|
|
389,473
|
|
|
|
684,936
|
|
|
|
797,614
|
|
|
|
Natural Gas(1) Sales Volumes (Mcf)
|
|
|
1,072,611
|
|
|
|
1,946,157
|
|
|
|
2,458,036
|
|
|
|
Total Sales Volumes (Boe)
|
|
|
568,241
|
|
|
|
1,009,295
|
|
|
|
1,207,287
|
|
|
|
Oil Average Sales Price per Bbl
|
|
$
|
50.66
|
|
|
$
|
50.54
|
|
|
$
|
55.19
|
|
|
|
Natural Gas Average Sales Price per Mcf
|
|
$
|
1.67
|
|
|
$
|
2.50
|
|
|
$
|
3.12
|
|
|
|
Average Lease Operating Expense per Boe
|
|
$
|
17.73
|
|
|
$
|
16.04
|
|
|
$
|
26.11
|
|
|
|
Proved Reserves (MBoe)
|
|
|
9,707
|
|
|
|
13,257
|
|
|
|
14,590
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
East Texas/North Louisiana
|
|
Oil Sales Volumes (Bbls)
|
|
|
1,323
|
|
|
|
2,566
|
|
|
|
2,616
|
|
|
|
Natural Gas(1) Sales Volumes (Mcf)
|
|
|
949,148
|
|
|
|
1,995,528
|
|
|
|
2,543,104
|
|
|
|
Total Sales Volumes (Boe)
|
|
|
159,514
|
|
|
|
335,154
|
|
|
|
426,467
|
|
|
|
Oil Average Sales Price per Bbl
|
|
$
|
53.56
|
|
|
$
|
55.70
|
|
|
$
|
50.09
|
|
|
|
Natural Gas Average Sales Price per Mcf
|
|
$
|
1.87
|
|
|
$
|
2.67
|
|
|
$
|
3.73
|
|
|
|
Average Lease Operating Expense per Boe
|
|
$
|
9.36
|
|
|
$
|
4.41
|
|
|
$
|
9.43
|
|
|
|
Proved Reserves (MBoe)
|
|
|
2,462
|
|
|
|
3,680
|
|
|
|
3,819
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
|
Oil Sales Volumes (Bbls)
|
|
|
390,796
|
|
|
|
687,502
|
|
|
|
800,230
|
|
|
|
Natural Gas(1) Sales Volumes (Mcf)
|
|
|
2,021,759
|
|
|
|
3,941,685
|
|
|
|
5,001,140
|
|
|
|
Total Sales Volumes (Boe)
|
|
|
727,756
|
|
|
|
1,344,450
|
|
|
|
1,633,754
|
|
|
|
Oil Average Sales Price per Bbl
|
|
$
|
50.67
|
|
|
$
|
50.56
|
|
|
$
|
55.18
|
|
|
|
Natural Gas Average Sales Price per Mcf
|
|
$
|
1.77
|
|
|
$
|
2.59
|
|
|
$
|
3.00
|
|
|
|
Average Lease Operating Expense per Boe
|
|
$
|
15.90
|
|
|
$
|
16.12
|
|
|
$
|
21.76
|
|
|
|
Proved Reserves (MBoe)
|
|
|
12,169
|
|
|
|
16,937
|
|
|
|
18,409
|
|
(1)
|
Production of natural gas liquids is immaterial and
included as a component of natural gas production.
|
Abandonment and Sale of Underlying Properties
Each of the operators of the Underlying
Properties or any transferee has the right to abandon its interest in any well or property if it reasonably believes a well or
property ceases to produce or is not capable of producing in commercially paying quantities. Upon termination of the lease, the
portion of the Net Profits Interest relating to the abandoned property will be extinguished.
The Sponsor generally may sell all or a
portion of its interests in the Underlying Properties, subject to and burdened by the Net Profits Interest, without the consent
of the Trust unitholders. 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. In addition, the
Sponsor may, without the consent of the Trust unitholders, require the Trustee to release the Net Profits Interest associated with
any lease that accounts for less than or equal to 0.25% of the total production from the Underlying Properties in the prior 12
months and provided that the Net Profits Interest covered by such releases cannot exceed, during any 12-month period, an aggregate
fair market value to the Trust of $500,000. These releases will be made only in connection with a sale by the Sponsor to a non-affiliate
of the relevant Underlying Properties and are conditioned upon the Trust receiving an amount equal to the fair value to the Trust
of such Net Profits Interest. In January 2019, the Sponsor sold two producing wells and associated acreage of the Underlying Properties
under this provision for a sale price of approximately $62,000, and the Trustee released such properties from the Net Profits Interest.
Title to Properties
The properties comprising the Underlying
Properties are or may be subject to one or more of the burdens and obligations described below. To the extent that these burdens
and obligations affect the Sponsor’s rights to production or the value of production from the Underlying Properties, they
have been taken into account in calculating the Trust’s interests and in estimating the size and the value of the reserves
attributable to the Underlying Properties.
The Sponsor’s interests in the oil
and natural gas properties comprising the Underlying Properties are typically subject to one or more of the following:
|
•
|
royalties and other burdens, express and implied, under oil and natural gas leases and other arrangements;
|
|
•
|
overriding royalties, production payments and similar interests and other burdens created by the Sponsor’s predecessors
in title;
|
|
•
|
a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and
other agreements that may affect the Underlying Properties or their title;
|
|
•
|
liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing unpaid suppliers
and contractors and contractual liens under operating agreements that are not yet delinquent or, if delinquent, are being contested
in good faith by appropriate proceedings;
|
|
•
|
pooling, unitization and communitization agreements, declarations and orders;
|
|
•
|
easements, restrictions, rights-of-way and other matters that commonly affect property;
|
|
•
|
conventional rights of reassignment that obligate the Sponsor to reassign all or part of a property to a third party if the
Sponsor intends to release or abandon such property;
|
|
•
|
preferential rights to purchase or similar agreements and required third party consents to assignments or similar agreements;
|
|
•
|
obligations or duties affecting the Underlying Properties to any municipality or public authority with respect to any franchise,
grant, license or permit, and all applicable laws, rules, regulations and orders of any governmental authority; and
|
|
•
|
rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties
and also the interests held therein, including the Sponsor’s interests and the Net Profits Interest.
|
The Sponsor has informed the Trustee that
the Sponsor believes the burdens and obligations affecting the properties comprising the Underlying Properties are conventional
in the industry for similar properties. The Sponsor has also informed the Trustee that the Sponsor believes the existing burdens
and obligations do not, in the aggregate, materially interfere with the use of the Underlying Properties and will not materially
adversely affect the Net Profits Interest or its value.
To give third parties notice of the Net
Profits Interest, Enduro recorded the Conveyance in Texas, Louisiana and New Mexico in the real property records in each Texas,
Louisiana or New Mexico county in which the Underlying Properties are located, or in such other public records of those states
as required under applicable law to place third parties on notice of the Conveyance.
In a bankruptcy of the Sponsor, to the extent
Louisiana or New Mexico law were held to be applicable, the Net Profits Interest might be considered an asset of the bankruptcy
estate and used to satisfy obligations to creditors of the Sponsor, in which case the Trust would be an unsecured creditor of the
Sponsor at risk of losing the entire value of the Net Profits Interest to senior creditors. See “Risk Factors—In the
event of the bankruptcy of the Sponsor, if a court were to hold that the Net Profits Interest was part of the bankruptcy estate,
the Trust may be treated as an unsecured creditor with respect to the Net Profits Interest attributable to properties in Louisiana
and New Mexico” in Item 1A of this Form 10-K.
The Sponsor believes that its title to the
Underlying Properties and the Trust’s title to the Net Profits Interest are each good and defensible in accordance with standards
generally accepted in the oil and gas industry, subject to such exceptions as are not so material to detract substantially from
the use or value of such Underlying Properties or Net Profits Interest. Under the terms of the Conveyance creating the Net Profits
Interest, the Sponsor has provided a special warranty of title with respect to the Net Profits Interest, subject to the burdens
and obligations described in this section. Please see “Risk Factors—The Trust Units may lose value as a result of title
deficiencies with respect to the Underlying Properties” in Item 1A of this Form 10-K.
|
Item 3.
|
Legal Proceedings.
|
Currently, there are not any legal proceedings
pending to which the Trust is a party or of which any of its property is the subject. The foregoing does not address any legal
proceedings to which the Sponsor or any of the third-party operators may be a party or subject or that may otherwise relate to
or affect any of the Underlying Properties or the operations of any of the operators of the Underlying Properties.
|
Item 4.
|
Mine Safety Disclosures.
|
Not applicable.