Indicate by check mark whether the registrant
(1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has
been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant
is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting
company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
If an emerging growth company, indicate
by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial
accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
The aggregate market value of Common Units
of Beneficial Interest of the Trust held by non-affiliates on June 28, 2019 (the last business day of its most recently completed
second quarter) was approximately $71.66 million based on the closing price as quoted on the New York Stock Exchange.
As of March 10, 2020, 52,500,000 Common
Units of Beneficial Interest in SandRidge Permian Trust were outstanding.
All references to “we,”
“us,” “our,” or the “Trust” refer to SandRidge Permian Trust. References to “SandRidge”
refer to SandRidge Energy, Inc., and where the context requires, its subsidiaries. The royalty interests conveyed by SandRidge
from its interests in specified oil and natural gas properties located in the Permian Basin in Andrews County, Texas (also referred
to as the “Underlying Properties”) and held by the Trust are referred to as the “Royalty Interests.”
As disclosed elsewhere in this Form 10-K, on November 1, 2018, SandRidge sold all of its interests in the Underlying
Properties and all of its outstanding common units of the Trust to Avalon Energy, LLC, a Texas limited liability company. Avalon
Energy, LLC is an affiliate of Avalon Exploration and Production LLC, a Texas limited liability company, and Avalon TX Operating,
LLC, a Texas limited liability company that is the operator of all of the wells burdened by the Royalty Interests. Avalon Energy,
LLC, Avalon Exploration and Production, LLC and Avalon TX Operating are collectively referred to herein as “Avalon.”
This report includes terms commonly used in the oil and natural gas industry, which are defined in the Glossary of Oil and Natural
Gas Terms below.
The following is a
description of the meanings of some of the oil and natural gas industry terms used in this report.
The area of a reservoir
considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent
undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically
producible oil or natural gas on the basis of available geoscience and engineering data. In the absence of data on fluid contacts,
proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration unless geoscience,
engineering or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation
from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data
and reliable technology establish the higher contact with reasonable certainty.
Reserves that can be
produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are
included in the proved classification when (i) successful testing by a pilot project in an area of the reservoir with properties
no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir,
or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project
or program was based and (ii) the project has been approved for development by all necessary parties and entities, including
governmental entities.
Existing economic conditions
include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price
during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic
average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions.
Reserves should not
be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated
as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a
non-productive reservoir (i.e. absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain
prospective resources (i.e. potentially recoverable resources from undiscovered accumulations).
(i) Reserves on
undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production
when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility
at greater distances.
(ii) Undrilled
locations are classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled
to be drilled within five years, unless the specific circumstances justify a longer time.
(iii) Under no
circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection
or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the
same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
This Annual Report
on Form 10-K includes “forward-looking statements” about the Trust, Avalon and other matters discussed herein
that are subject to risks and uncertainties within the meaning of Section 27A of the Securities Act of 1933, as amended, (the
“Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange
Act”). All statements other than statements of historical fact included in this document, including, without limitation,
statements under “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item
7 and “Risk Factors” in Item 1A and elsewhere herein regarding the proved oil, natural gas and NGL reserves associated
with the Underlying Properties, the Trust’s or Avalon’s future financial position, business strategy, project costs
and plans and objectives for future operations, information regarding costs and information regarding production and reserve growth,
are forward-looking statements. Actual outcomes and results may differ materially from those projected. Forward-looking statements
are generally accompanied by words such as “estimate,” “target,” “project,” “predict,”
“believe,” “expect,” “anticipate,” “potential,” “could,” “may,”
“foresee,” “plan,” “goal,” “should,” “intend” or other words that convey
the uncertainty of future events or outcomes. We have based these forward-looking statements on our current expectations and assumptions
about future events. These statements are based on certain assumptions made by us in light of our experience and our perception
of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under
the circumstances. However, whether actual results and developments will conform with our expectations and predictions is subject
to a number of risks and uncertainties, including the risk factors discussed in Item 1A of this report, which could affect the
future results of the energy industry in general, and the Trust and Avalon in particular, and could cause those results to differ
materially from those expressed in such forward-looking statements. The actual results or developments anticipated may not be realized
or, even if substantially realized, they may not have the expected consequences to or effects on Avalon’s business or the
Trust’s results. Such statements are not guarantees of future performance and actual results or developments may differ materially
from those projected in such forward-looking statements. The Trust undertakes no obligation to publicly update or revise any forward-looking
statements.
PART I
Item 1. Business
General
SandRidge Permian
Trust is a statutory trust formed under the Delaware Statutory Trust Act pursuant to a trust agreement, as amended and restated,
by and among SandRidge, as Trustor, The Bank of New York Mellon Trust Company, N.A., as Trustee (the “Trustee”),
and The Corporation Trust Company, as Delaware Trustee (the “Delaware Trustee”) (such amended and restated trust
agreement, as amended to date, the “Trust Agreement”) in May 2011. The Trust’s affairs are administered
by the Trustee, which maintains its offices at 601 Travis Street, 16th Floor, Houston, Texas 77002. The Trust does not
have any employees.
Copies of reports
filed by the Trust under the Exchange Act are available to Trust unitholders and the public promptly after such materials are filed
with or furnished to the Securities and Exchange Commission (“SEC”) by accessing the EDGAR system maintained
by the SEC at www.sec.gov/edgar. Certain information concerning the Trust and Trust units as well as a link to the Trust’s
filings with the SEC may be obtained at the following website location: www.businesswire.com/cnn/per.htm. The Trust will
also provide electronic or paper copies of its filings free of charge upon request to the Trustee.
Formation and Structure.
The Trust was formed to own Royalty Interests in specified oil and natural gas properties located in Andrews County, Texas
(the “Underlying Properties”) conveyed by SandRidge to the Trust pursuant to the terms set forth in conveyancing
documents effective April 1, 2011 (the “Conveyances”) concurrent with the initial public offering and sale
of 34,500,000 of the Trust’s common units (“Common Units”) in August 2011 (the “Offering”).
As consideration for conveyance of the Royalty Interests, the Trust remitted the net proceeds of the offering, along with 4,875,000
Common Units and 13,125,000 unregistered subordinated units of the Trust (“Subordinated Units”), to certain
wholly owned subsidiaries of SandRidge. The Common Units and the Subordinated Units are collectively referenced in this Form 10-K
as the “Trust units”.
The Royalty Interests
entitle the Trust to receive (a) 80% of the proceeds (after deducting post-production costs and any applicable taxes) from
the sale of oil, natural gas and NGL production attributable to the net revenue interest of SandRidge in 517 oil and natural gas
wells drilled and completed as of April 1, 2011 on the Underlying Properties, including 21 wells awaiting Completion at that
time (the “Initial Wells”), and (b) 70% of the proceeds (after deducting post-production costs and any
applicable taxes) from the sale of oil, natural gas and NGL production attributable to the net revenue interest in 888 development
wells drilled and completed by an affiliate of SandRidge pursuant to the terms of a development agreement between the Trust and
SandRidge (the “Trust Development Wells”) within an area of mutual interest (“AMI”) designated
in the development agreement. The development agreement obligated SandRidge to drill and complete the Trust Development Wells by
March 31, 2016. SandRidge fulfilled this obligation in November 2014, and, as a result, the development agreement terminated
and the Subordinated Units issued to SandRidge were converted to Common Units in January 2016 pursuant to the terms of the
Trust Agreement.
On November 1,
2018, SandRidge sold all of its interests in the Underlying Properties and all Common Units which it owned to Avalon Energy, LLC,
a Texas limited liability company. In connection with this transaction (the “Sale Transaction”), Avalon Exploration
and Production LLC, an affiliate of Avalon Energy, LLC, assumed all of SandRidge’s obligations under the Trust Agreement
and the administrative services agreement between SandRidge and the Trust (as further described below). Avalon Energy, LLC and
Avalon Exploration and Production LLC are collectively referred to as “Avalon” in this report. As a part of
the Sale Transaction, SandRidge and Avalon entered into a transition services agreement whereby SandRidge provided certain transition
services to Avalon, including trust administration services, through April 30, 2019. The transition services agreement has
expired. At December 31, 2019, Avalon owned 13,125,000 Common Units, or 25% of all issued and outstanding Trust units.
As was the case with
SandRidge prior to the Sale Transaction, pursuant to the terms of the Conveyances, Avalon is obligated to act in good faith and
as a reasonably prudent operator under the same or similar circumstances as it would if it were acting with respect to its own
properties, disregarding the existence of the Royalty Interests as burdens affecting such properties (the “Reasonably
Prudent Operator Standard”). The Conveyances generally permit Avalon to sell all or any part of its interest in the Underlying
Properties, if the Underlying Properties are sold subject to and burdened by the Royalty Interests.
The Trust is passive
in nature and neither the Trust nor the Trustee has any control over, or responsibility for, any operating or capital costs related
to the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. However, the Trustee has no
authority over or responsibility for, and no involvement with, any aspect of the oil and natural gas operations or other activities
with respect to the Underlying Properties. The Trust Agreement generally limits the Trust’s business activities to owning
the Royalty Interests and certain activities reasonably related thereto, including activities required or permitted by the terms
of the Conveyances related to the Royalty Interests.
The Trust will dissolve
and begin to liquidate on March 31, 2031 (the “Termination Date”), unless sooner dissolved pursuant to
the terms of the Trust Agreement as described below and will soon thereafter wind up its affairs and terminate. At the Termination
Date, 50% of the Royalty Interests will revert automatically to Avalon. The remaining 50% of the Royalty Interests will be sold
at that time, and the net proceeds of the sale, as well as any remaining Trust cash reserves, will be distributed to the unitholders
on a pro rata basis, subject to Avalon's right of first refusal to purchase the Royalty Interests retained by the Trust at the
Termination Date. The Trust may also dissolve should one of the following events occur prior to the Termination Date: (a) the
Trust sells all of the Royalty Interests; (b) cash available for distribution for any four consecutive quarters, on a cumulative
basis, is less than $5.0 million; (c) the Trust unitholders approve an earlier dissolution of the Trust; or (d) the Trust
is judicially dissolved pursuant to the Delaware Statutory Trust Act. In the case of any of the foregoing, the Trustee would then
sell all of the Trust’s assets (subject to Avalon’s right of first refusal to purchase the Royalty Interests retained
by the Trust as of the date of such event), either by private sale or public auction, and distribute the net proceeds of the sale
to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities.
The Trust is highly
dependent on Avalon for multiple services, including: (a) the operation of the Underlying Properties and wells located thereon;
(b) the marketing and sale of hydrocarbon production from the wells; (c) the remittance of net proceeds from the sale
of production from wells burdened by the Royalty Interests to the Trust; (d) administrative services such as accounting, tax
preparation, bookkeeping and informational services performed on behalf of the Trust; and (e) the preparation and filing of
reports the Trust is or may be required to prepare and/or file in accordance with applicable tax and securities laws, exchange
listing rules and other requirements. The ability to operate the Underlying Properties depends on Avalon’s future financial
condition and economic performance, access to capital, and other factors, many of which are out of Avalon’s control. If the
reduced demand for crude oil in the global market resulting from the economic effects of the coronavirus pandemic and the recent
reduction in the benchmark price of crude oil persist for the near term or longer, such factor are likely to have a negative impact
on Avalon’s financial condition. This negative impact could affect Avalon’s ability to operate the wells and provide
services to the Trust.
Income Tax Considerations.
The Trust is treated as a partnership for federal and applicable state income tax purposes, and Trust unitholders are treated as
partners in that partnership for such purposes. For United States (“U.S.”) federal income tax purposes, a partnership
is not a taxable entity and incurs no U.S. federal income tax liability. With respect to state taxation, a partnership typically
is treated in the same manner as it is for U.S. federal income tax purposes. Each partner is required to take into account his
or her share of items of income, gain, loss, deduction and credit of the partnership in computing his or her federal income tax
liability, regardless of whether cash distributions are made to him or her by the partnership. Distributions by a partnership to
a partner generally are not taxable to the partner (but instead reduce tax basis but not below zero) unless the amount of cash
distributed to such partner is in excess of the partner’s adjusted tax basis in his or her partnership interest. To date,
the Trust has distributed an amount of cash to Trust unitholders in excess of their cash contributions made at the time of the
initial public offering of Common Units.
The Trust’s activities
occur solely in Texas and, as a result, the Trust is deemed to have “nexus” under the Texas franchise tax laws. Therefore,
the Trust is required to pay Texas franchise tax each year at a maximum effective rate (subject to changes in the statutory rate)
of 0.1655% of all gross income.
Agreements with Avalon
In conjunction with
the conveyance of the Royalty Interests to the Trust, the Trust entered into the following agreements with SandRidge and/or one
of its wholly-owned subsidiaries, which agreements were subsequently assigned to Avalon in connection with the Sale Transaction:
Administrative
Services Agreement. The Trust is a party to an administrative services agreement with Avalon, as assignee of SandRidge (the
“Administrative Services Agreement”), that obligates the Trust to pay Avalon an annual administrative services
fee in the amount of $300,000, payable quarterly, for accounting, tax preparation, bookkeeping and informational services to be
performed by Avalon on behalf of the Trust. Avalon is also entitled to receive reimbursement for its out-of-pocket fees, costs
and expenses incurred in connection with the provision of any of the services provided under this agreement. In connection with
the Sale Transaction, Avalon assumed the responsibility to provide such services to the Trust under the terms of the Administrative
Services Agreement effective November 1, 2018.
The Administrative
Services Agreement will terminate on the earliest to occur of: (a) the date the Trust shall have dissolved and commenced winding
up in accordance with the Trust Agreement; (b) the date that all of the Royalty Interests have been terminated or are no longer
held by the Trust; (c) pertaining to administrative services being provided by Avalon, the date that either Avalon or the
Trustee may designate by delivering written notice no less than 90 days prior to such date, provided that Avalon cannot terminate
the agreement except in connection with the transfer of some or all of the Underlying Properties and the transferee thereof assuming
responsibility to perform the services in place of Avalon; and (d) a date mutually agreed by Avalon and the Trustee.
Registration Rights
Agreement. The Trust entered into a registration rights agreement for the benefit of SandRidge and certain of its affiliates
and transferees, pursuant to which the Trust agreed to register the offering of unregistered Trust units, now held by Avalon, upon
request. Upon the closing of the Sale Transaction, Avalon assumed the rights and obligations of SandRidge under the registration
rights agreement. Specifically, the Trust agreed:
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to use its reasonable best efforts to file a registration statement, including, if so requested,
a shelf registration statement, with the SEC within 45 days of receipt of a notice requesting the filing of a registration statement
from Avalon;
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to use its reasonable best efforts to cause the registration statement or shelf registration statement
to be declared effective under the Securities Act as promptly as practicable after the filing thereof; and
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to continuously maintain the effectiveness of the registration statement under the Securities Act
for 90 days (or continuously if a shelf registration statement is requested) after the effectiveness thereof or until the Trust
units covered by the registration statement have been sold pursuant to such registration statement or until all registrable Trust
units:
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have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does
not receive “restricted securities”;
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have been sold in a private transaction in which the transferor’s rights under the registration
rights agreement are not assigned to the transferee of the Trust units; or
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become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under
the Securities Act).
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The holders will have the right to require
the Trust to file no more than five registration statements in aggregate, one of which has been filed to date on behalf of SandRidge.
The Trust does not bear any expenses associated with such transactions.
Trust Agreement
The Trust Agreement
provides that the Trust’s business activities are generally limited to owning the Royalty Interests and administrative activities
related thereto as set forth in the Trust Agreement, including activities required or permitted by the terms of the Conveyances
related to the Royalty Interests. The Trust is not permitted to acquire other oil and natural gas properties or royalty interests
and is not able to issue any additional Trust units.
The beneficial interest
in the Trust is divided into 52,500,000 Trust units, which now consist solely of Common Units. Each Trust unit represents an equal
undivided beneficial interest in the property of the Trust.
Amendment of the Trust
Agreement generally requires the vote of holders of (i) a majority of the Trust units (excluding Trust units owned by Avalon)
and (ii) a majority of the Trust units (including Trust units owned by Avalon), in each case voting in person or by proxy
at a meeting of such unitholders at which a quorum is present. At any time that Avalon owns less than 10% of the total Trust units
outstanding, however, the standard for approval will be the vote of the holders of a majority of the Trust units, including Trust
units owned by Avalon, voting in person or by proxy at a meeting of the unitholders at which a quorum is present. Abstentions and
broker non-votes will not be deemed to be a vote cast. However, no amendment may:
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increase the power of the Trustee to engage in business or investment activities;
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alter the rights of the Trust unitholders as among themselves; or
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permit the Trustee to distribute the Royalty Interests in kind.
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Amendments to the Trust Agreement’s
provisions addressing the following matters may not be made without Avalon’s consent:
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dispositions of the Trust’s assets;
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indemnification of the Trustee;
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reimbursement of out-of-pocket expenses of Avalon when acting as the Trust’s agent;
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termination of the Trust; and
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amendments of the Trust Agreement.
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Certain amendments
to the Trust Agreement do not require the vote of the Trust unitholders. See “Permitted Amendments” below.
The business and affairs
of the Trust are managed by the Trustee. The Trustee has no ability to manage or influence the operations of the Underlying Properties.
Avalon operates the Underlying Properties, but has no ability to manage or influence the management of the Trust, except
through its limited voting rights as a holder of Trust units.
Duties and Powers
of the Trustee. The duties and powers 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 Trust Agreement provides that the Trustee does not have any duties or liabilities,
including fiduciary duties, except as expressly set forth in the Trust Agreement, and the duties and liabilities of the Trustee
as set forth in the Trust Agreement replace any other duties and liabilities, including fiduciary duties, to which the Trustee
might otherwise be subject.
The Trustee’s
principal duties consist of:
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collecting cash proceeds attributable to the Royalty Interests;
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paying expenses, charges and obligations of the Trust from the Trust’s assets;
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making cash distributions to the Trust unitholders in accordance with the Trust Agreement;
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causing to be prepared and distributed a Schedule K-1 for each Trust unitholder and preparing and
filing tax returns on behalf of the Trust; and
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causing to be prepared and filed reports required to be filed under the Exchange Act and under
the rules of any securities exchange or quotation system on which the Trust units are listed or admitted to trading.
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Avalon provides, and
SandRidge provided prior to the Sale Transaction, administrative and other services to the Trust in fulfillment of certain of the
foregoing duties, pursuant to the terms of the Administrative Services Agreement. SandRidge performed these services on behalf
of, and in conjunction with, Avalon pursuant to the terms of the transition services agreement, which terminated on April 30,
2019.
Except as set forth below, cash held by
the Trustee as a reserve against future liabilities must 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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Alternatively, cash held for distribution
at the next distribution date may be held in a non-interest-bearing account.
The Trust may not acquire
any asset except the Royalty Interests and cash and temporary cash investments, and it may not engage in any investment activity
except investing cash on hand.
The Trust Agreement
provides that the Trustee will not make business decisions affecting the assets of the Trust. However, the Trustee may:
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prosecute or defend, and settle, claims of or against the Trust or its agents;
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retain professionals and other third parties to provide services to the Trust;
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charge for its services as Trustee;
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retain funds to pay for future expenses and deposit them with one or more banks or financial institutions
(which may include the Trustee to the extent permitted by law);
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lend funds at commercial rates to the Trust to pay the Trust’s expenses; and
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seek reimbursement from the Trust for its out-of-pocket expenses.
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In carrying out its
powers and performing its duties to Trust unitholders, the Trustee may act directly or in its discretion (at the expense of the
Trust) through agents pursuant to agreements entered into with any of them, and the Trustee will be liable to the Trust unitholders
only for its own willful misconduct, acts or omissions made in bad faith, gross negligence, or taxes, fees or other charges based
on any fees, commissions or compensation received by it in connection with any of the transactions contemplated by the Trust Agreement.
The Trustee will not be liable for any act or omission of its agents unless the Trustee acted with willful misconduct, bad faith
or gross negligence in its selection and retention of such agents. The Trustee and its affiliates, as well as each of its agents
(including Avalon when acting in its capacity as an agent), will be indemnified and held harmless by, and receive reimbursement
from, the Trust against and from any liability or cost that it incurs individually in the administration of the Trust, except in
cases of willful misconduct, bad faith or gross negligence. The Trustee has a lien on the assets of the Trust as security for this
indemnification and its compensation earned as Trustee. Trust unitholders will not be liable to the Trustee for any indemnification.
The Trustee ensures that all contractual liabilities of the Trust are limited to the assets of the Trust. The Trustee has not loaned
and does not intend to lend funds to the Trust.
Merger or Consolidation
of Trust. The Trust may merge or consolidate with or into, or convert into, one or more limited partnerships, general partnerships,
corporations, business trusts, limited liability companies, or associations or unincorporated businesses if such transaction is
agreed to by the Trustee and approved by the vote of the holders of (i) a majority of the Trust units (excluding Trust units
owned by Avalon) and (ii) a majority of the Trust units (including Trust units owned by Avalon), in each case voting in person
or by proxy at a meeting of such holders at which a quorum is present and such transaction is permitted under the Delaware Statutory
Trust Act and any other applicable law. At any time that Avalon owns less than 10% of the total Trust units outstanding, however,
the standard for approval will be the vote of the holders of a majority of the Trust units, including Trust units owned by Avalon,
voting in person or by proxy at a meeting of such holders at which a quorum is present.
Trustee’s
Power to Sell Royalty Interests. The Trustee may sell the Royalty Interests under any of the following circumstances:
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the sale is requested by Avalon in accordance with the provisions of the Trust Agreement; or
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the sale is approved by the vote of the holders of (i) a majority of the Trust units (excluding
Trust units owned by Avalon) and (ii) a majority of the Trust units (including Trust units owned by Avalon), in each case
voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at any time that Avalon owns
less than 10% of the total Trust units outstanding, the standard for approval will be the vote of the holders of a majority of
the Trust units, including Trust units owned by Avalon, voting in person or by proxy at a meeting of such holders at which a quorum
is present.
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Upon dissolution of the Trust, the Trustee
must sell those Royalty Interests that do not revert automatically to Avalon pursuant to the terms of the Trust Agreement. No Trust
unitholder approval is required in this event.
The Trustee will distribute
the net proceeds from any sale of the Royalty Interests and other assets to the Trust unitholders after payment or reasonable provision
for payment of all liabilities of the Trust, including any amounts owed to its agents (including Avalon acting in such capacity).
Permitted Amendments.
The Trustee may amend or supplement the Trust Agreement, the conveyances, the Administrative Services Agreement, or the registration
rights agreement, without the approval of the Trust unitholders, to cure ambiguities, to correct or supplement defective or inconsistent
provisions, to grant any benefit to all Trust unitholders, to evidence or implement any changes required by applicable law, or
to change the name of the Trust; provided, however, that any such supplement or amendment does not adversely affect
the interests of the Trust unitholders. Furthermore, the Trustee, acting alone, may amend the Administrative Services Agreement
without the approval of Trust unitholders if such amendment would not increase the cost or expense of the Trust or create an adverse
economic impact on the Trust unitholders.
All other permitted
amendments to the Trust Agreement and other agreements listed above may only be made by the vote of the holders of (i) a majority
of the Trust units (excluding Trust units owned by Avalon) and (ii) a majority of the Trust units (including Trust units owned
by Avalon), in each case voting in person or by proxy at a meeting of such holders at which a quorum is present; except that at
any time that Avalon owns less than 10% of the total Trust units outstanding, the standard for approval will be the vote of the
holders of a majority of the Trust units, including Trust units owned by Avalon, voting in person or by proxy at a meeting of such
holders at which a quorum is present. Abstentions and broker non-votes will not be deemed to be a vote cast.
Miscellaneous.
The Trustee may consult with legal counsel (which may include legal counsel to Avalon), accountants, tax advisors, geologists and
engineers and other parties the Trustee believes to be qualified as experts on the matters for which advice is sought. The Trustee
will be protected for any action it takes in good faith reliance upon the opinion of an expert.
The Delaware Trustee
and the Trustee may resign at any time or be removed with or without cause at any time by the vote of the holders of a majority
of the Trust units (excluding Trust units owned by Avalon), voting in person or by proxy at a meeting of such holders at which
a quorum is present; except that at any time that Avalon owns less than 10% of the outstanding Trust units, the standard for approval
will be the vote of the holders of a majority of the Trust units, including Trust units owned by Avalon, voting in person or by
proxy at a meeting of such holders at which a quorum is present. Abstentions and broker non-votes will not be deemed to be a vote
cast. Any successor must be a bank or trust company meeting certain requirements including having combined capital, surplus and
undivided profits of at least $20 million, in the case of the Delaware Trustee, and $100 million, in the case of the Trustee.
Distributions
The Trustee makes
quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative
expenses, property taxes and Texas franchise taxes, and cash reserves withheld by the Trustee, on or about the 60th day following
the completion of each quarter. Each distribution covers production for a three-month period. The amount of Trust revenues and
cash distributions to Trust unitholders depends on:
|
|
•
|
oil, natural gas and NGL prices received;
|
|
|
•
|
volume of oil, natural gas and NGL produced and sold;
|
|
|
•
|
post-production costs (which includes internal costs and third person costs incurred by Avalon)
and any applicable taxes; and
|
|
|
•
|
the Trust’s general and administrative expenses.
|
The amount of the quarterly
distributions will fluctuate from quarter to quarter, depending on the factors discussed above. There is no minimum required distribution.
See Note 4 to the financial statements contained in Item 8 of this report for further discussion of Trust distributions.
If at any time the
Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary course administrative
expenses as they become due, the Trust may borrow funds from the Trustee or other lenders, including Avalon, to pay such expenses.
The Trustee has not loaned and does not intend to lend funds to the Trust. If such funds are borrowed, no further distributions
will be made to Trust unitholders (except in respect of any previously determined quarterly distribution amount) until the borrowed
funds have been repaid.
The Trust Agreement
provides that, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s
ordinary course administrative expenses as they become due, Avalon (as assignee of SandRidge) will, at the Trustee’s request,
loan funds to the Trust necessary to pay such expenses. Any such loan will be on an unsecured basis, and the terms of such loan
will be substantially the same as those which would be obtained in an arms’ length transaction between Avalon and an unaffiliated
third party. If Avalon provides such funds to the Trust, Avalon may permit the Trust to make distributions prior to Avalon being
repaid for such loan. In addition, Avalon would become a creditor of the Trust and its interest as a creditor could conflict with
the interests of other Trust unitholders. The Trust did not borrow funds from SandRidge, and to date, the Trust has not borrowed
funds from Avalon.
Properties
As of December 31,
2019, 2018 and 2017, the Trust’s properties consisted of Royalty Interests in (a) the Initial Wells and (b) 856
additional wells (equivalent to 888 Trust Development Wells under the development agreement) that were drilled and perforated for
Completion between April 1, 2011 and December 31, 2014. SandRidge was credited for having drilled one full Trust Development
Well if a well was drilled and perforated for Completion to the Grayburg/San Andres formation and SandRidge’s net revenue
interest in the well was equal to 69.3%. For wells in which SandRidge had a net revenue interest equal to or greater than 69.3%,
SandRidge received proportionate credit for such well. The wells are located on properties situated in the greater Fuhrman-Mascho
field, a field in Andrews County, Texas, that produces primarily oil from the Grayburg/San Andres formation in the Permian Basin.
Proved Reserves.
The following estimates of net proved oil, natural gas and NGL reserves are based on reserve reports prepared by Netherland, Sewell &
Associates, Inc. (“Netherland Sewell”), independent petroleum engineers. The PV-10 and Standardized Measure
shown in the table below are not intended to represent the current value of estimated oil, natural gas and NGL reserves attributable
to the Royalty Interests as of the dates shown. The reserve reports as of December 31, 2019, 2018 and 2017 were based on the
average price during the 12-month periods ended December 31, 2019, 2018 and 2017, using first-day-of-the-month prices for
each month. Refer to “Risk Factors” in Item 1A of this report and “Trustee’s Discussion and Analysis of
Financial Condition and Results of Operations” in Item 7 of this report in evaluating the reserve information presented below.
Avalon provides, and
SandRidge provided prior to the Sale Transaction, certain services respecting the estimation of net proved oil, natural gas and
NGL reserves to the Trust pursuant to the terms of the Administrative Services Agreement. SandRidge performed these services on
behalf of, and in conjunction with, Avalon pursuant to the terms of the transition services agreement, until April 30, 2019
(the date on which such agreement terminated). Consistent with past practice, the process begins with an Avalon staff reservoir
engineer collecting and verifying all pertinent data, including but not limited to well test data, production data, historical
pricing, cost information, property ownership interests, reservoir data, and geosciences data. This data was reviewed by various
levels of Avalon management for accuracy, before consultation with the independent petroleum engineers. Members of Avalon management,
including its staff reservoir engineer, regularly consulted with the independent petroleum engineers during the reserve estimation
process to review properties, assumptions, and any new data available. The internal reserve estimates completed and methodologies
used by Avalon were compared to the independent petroleum engineers’ estimates and conclusions before the reserve estimates
were included in the independent petroleum engineers’ reports. Additionally, members of Avalon’s senior management
reviewed and approved the reserve reports contained herein.
Internal Controls.
Avalon’s Vice President - Petroleum Engineering is the technical person primarily responsible for overseeing the preparation
of the Trust’s reserve estimates on behalf of the Trustee. He has a Bachelor of Science degree in Civil Engineering with
over 40 years of practical industry experience, including estimating and evaluating reserve information. In addition, he has been
a certified professional engineer in the State of Texas since July 1983 and a member of the Society of Petroleum Engineers
since 1975.
In order to ensure
the reliability of reserves estimates, Avalon’s internal controls observed within the reserve estimation process included:
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•
|
No employee’s compensation is tied to the amount of reserves booked.
|
|
|
•
|
Reserves estimates are prepared by experienced reservoir engineers or under their direct supervision.
|
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|
•
|
The Vice President - Petroleum Engineering reports directly to Avalon’s President.
|
|
|
•
|
Avalon management follows comprehensive SEC-compliant internal policies to determine and report
proved reserves including:
|
|
|
•
|
confirming that reserve estimates include all applicable properties and are based upon proper working
and net revenue interests;
|
|
|
•
|
reviewing and using in the estimation process data provided by other departments within Avalon,
such as Accounting; and
|
|
|
•
|
comparing and reconciling internally generated reserve estimates to those prepared by third parties.
|
The independent petroleum
engineers estimated all of the proved reserve information in these reserve reports in accordance with the definitions and guidelines
of the SEC and in conformity with the Accounting Standards Codification Topic 932, Extractive Activities-Oil and Gas. Neither Netherland
Sewell nor any officer or employee of Avalon owns an interest in any of the Underlying Properties, nor are they employed on a contingent
basis. The qualifications of Netherland Sewell’s technical personnel primarily responsible for overseeing the preparation
of the Trust’s reserves estimates included in this report include the following:
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|
•
|
practicing consulting petroleum engineering since 2013 and over 14 years of prior industry experience;
|
|
|
•
|
licensed professional engineers in the State of Texas; and
|
|
|
•
|
a Bachelor of Science Degree in Chemical Engineering.
|
These qualifications meet or exceed the
Society of Petroleum Engineers’ standard requirements to be a professionally qualified Reserve Estimator and Auditor.
Reporting of Natural
Gas Liquids. Natural gas liquids, or NGL, are produced as a result of the processing of a portion of the Trust’s natural
gas production stream. At December 31, 2019, NGL constituted approximately 9% of the Trust’s total proved reserves on
a barrel equivalent basis and represented volumes to be produced from properties where contracts are in place for the extraction
and separate sale of NGL. NGL are products sold by the gallon. In reporting proved reserves and production of NGL, production and
reserves have been included in barrels. The extraction of NGL in the processing of natural gas reduces the volume of natural gas
available for sale. All production information related to natural gas is reported net of the effect of any reduction in natural
gas volumes resulting from the processing and extraction of NGL.
A summary of the Trust’s
proved oil, natural gas and NGL reserves, all of which are located in the State of Texas, is presented below:
|
|
|
December 31,
|
|
|
Estimated Proved Reserves(1)
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
Developed
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
3,918.7
|
|
|
|
4,567.5
|
|
|
|
4,999.9
|
|
|
NGL (MBbls)
|
|
|
411.5
|
|
|
|
691.8
|
|
|
|
758.9
|
|
|
Natural gas (MMcf)
|
|
|
1,359.1
|
|
|
|
2,163.8
|
|
|
|
2,544.4
|
|
|
Total proved developed (MBoe)(2)
|
|
|
4,556.8
|
|
|
|
5,619.9
|
|
|
|
6,182.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Undeveloped(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
NGL (MBbls)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Natural gas (MMcf)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Total proved undeveloped (MBoe)(2)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Proved
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
3,918.7
|
|
|
|
4,567.5
|
|
|
|
4,999.9
|
|
|
NGL (MBbls)
|
|
|
411.5
|
|
|
|
691.8
|
|
|
|
758.9
|
|
|
Natural gas (MMcf)
|
|
|
1,359.1
|
|
|
|
2,163.8
|
|
|
|
2,544.4
|
|
|
Total proved (MBoe)(2)
|
|
|
4,556.8
|
|
|
|
5,619.9
|
|
|
|
6,182.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PV-10 (in millions)(4)
|
|
$
|
104.0
|
|
|
$
|
135.7
|
|
|
$
|
123.2
|
|
|
Standardized Measure of Discounted Net Cash Flows (in millions)(5)
|
|
$
|
103.8
|
|
|
$
|
135.5
|
|
|
$
|
123.0
|
|
|
|
(1)
|
Determined using a 12-month average of the first-day-of-the-month index price without giving effect
to derivative transactions. The prices used in the reserve report yield weighted average wellhead prices, which are based on first-day-of-the-month
index prices and adjusted for transportation and regional price differentials. The index prices and the equivalent weighted average
wellhead prices are shown in the table below.
|
|
|
|
Weighted average wellhead prices
|
|
|
Index prices
|
|
|
|
|
Oil (per Bbl)
|
|
|
NGL
(per Bbl)
|
|
|
Natural gas
(per Mcf)
|
|
|
Oil (per Bbl)
|
|
|
Natural gas
(per Mcf)
|
|
|
December 31, 2019
|
|
$
|
51.58
|
|
|
$
|
19.55
|
|
|
$
|
0.88
|
|
|
$
|
55.85
|
|
|
$
|
2.58
|
|
|
December 31, 2018
|
|
$
|
59.12
|
|
|
$
|
24.91
|
|
|
$
|
1.89
|
|
|
$
|
65.56
|
|
|
$
|
3.10
|
|
|
December 31, 2017
|
|
$
|
47.70
|
|
|
$
|
20.07
|
|
|
$
|
2.13
|
|
|
$
|
51.34
|
|
|
$
|
2.98
|
|
|
|
(2)
|
Barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil,
which approximates the relative energy content of oil as compared to natural gas.
|
|
|
(3)
|
Royalty Interests conveyed to the Trust by Avalon were in proved properties only.
|
|
|
(4)
|
PV-10 is the present value of estimated future net revenue to be generated from the production
of proved reserves, discounted at 10% per annum to reflect timing of future cash flows and calculated without deducting future
income taxes. PV-10 is a non-GAAP financial measure and generally differs from standardized measure of discounted net cash flows,
or Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income
taxes on future net revenues. Neither PV-10 nor Standardized Measure are intended to represent an estimate of fair market value
of the Royalty Interests. PV-10 is used by the industry as an arbitrary reserve asset value measure to compare the relative size
and value of the proved reserves held by companies without regard to the specific tax characteristics of such entities. The following
table provides a reconciliation of Standardized Measure to PV-10:
|
|
|
|
December 31,
|
|
|
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
(in millions)
|
|
|
Standardized Measure of Discounted Net Cash Flows (4)
|
|
$
|
103.8
|
|
|
$
|
135.5
|
|
|
$
|
123.0
|
|
|
Present value of future income tax discounted at 10%
|
|
|
0.2
|
|
|
|
0.2
|
|
|
|
0.2
|
|
|
PV-10
|
|
$
|
104.0
|
|
|
$
|
135.7
|
|
|
$
|
123.2
|
|
|
|
(5)
|
Standardized Measure represents the present value of estimated future cash inflows from proved
oil, natural gas and NGL reserves, less future development and production costs, and income tax expenses, discounted at 10% per
annum to reflect timing of future cash flows and using the same pricing assumptions as are used to calculate PV-10. Standardized
Measure differs from PV-10 as Standardized Measure includes the effect of future income taxes.
|
Proved reserves are
those quantities of oil, natural gas and NGL that, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions,
operating methods and government regulations, prior to the time at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for
estimation. To be classified as proved reserves, the project to extract the oil or natural gas must have commenced or the operator
must be reasonably certain that it will commence the project within a reasonable period of time.
The area of a reservoir
considered proved includes (i) the area identified by drilling and limited by fluid contacts, if any, and (ii) adjacent
undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with the identified area and
to contain economically producible oil or natural gas on the basis of available geoscience and engineering data. In the absence
of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons as seen in a well penetration
unless geoscience, engineering or performance data and reliable technology establish a lower contact with reasonable certainty.
Where direct observation
from well penetrations has defined a highest known oil elevation and the potential exists for an associated gas cap, proved oil
reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data
and reliable technology establish the higher contact with reasonable certainty.
Reserves that can
be produced economically through application of improved recovery techniques (such as fluid injection) are included in the proved
classification when (i) successful testing by a pilot project in an area of the reservoir with properties no more favorable
than in the reservoir as a whole, the operation of an installed program in the reservoir, or an analogous reservoir, or other evidence
using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was
based and (ii) the project has been approved for development by all necessary parties and entities, including governmental
entities.
Existing economic
conditions include prices and costs at which hydrocarbons can be economically produced from a known reservoir. In determining the
amount of proved reserves, the price used must be the average price during the 12-month period prior to the ending date of the
period covered by the reserve report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each
month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
Proved Undeveloped Reserves.
SandRidge was obligated
to drill, or cause to be drilled, the Trust Development Wells by March 31, 2016. SandRidge fulfilled its drilling obligation
to the Trust in November 2014, and neither SandRidge nor Avalon has any future drilling obligations to the Trust. Accordingly,
the Trust has not had any proved undeveloped reserves since December 31, 2014 and will not have any proved undeveloped reserves
in the future.
Production and Price History
The following tables
set forth information regarding the net oil, natural gas and NGL production attributable to the Royalty Interests and certain price
and cost information for each of the periods indicated.
|
|
|
Year Ended December 31,
|
|
|
|
|
2019 (1)
|
|
|
2018 (2)
|
|
|
2017 (3)
|
|
|
Production Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
414
|
|
|
|
485
|
|
|
|
584
|
|
|
NGL (MBbls)
|
|
|
57
|
|
|
|
72
|
|
|
|
83
|
|
|
Natural gas (MMcf)
|
|
|
181
|
|
|
|
227
|
|
|
|
281
|
|
|
Combined equivalent volumes (MBoe)(4)
|
|
|
501
|
|
|
|
595
|
|
|
|
714
|
|
|
Average daily combined equivalent volumes (MBoe/d)
|
|
|
1.4
|
|
|
|
1.6
|
|
|
|
2.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (per Bbl)
|
|
$
|
50.77
|
|
|
$
|
56.96
|
|
|
$
|
45.44
|
|
|
NGL (per Bbl)
|
|
$
|
20.00
|
|
|
$
|
24.16
|
|
|
$
|
19.27
|
|
|
Combined oil and NGL (per Bbl)
|
|
$
|
47.06
|
|
|
$
|
52.70
|
|
|
$
|
42.18
|
|
|
Natural gas (per Mcf)
|
|
$
|
1.22
|
|
|
$
|
1.91
|
|
|
$
|
2.30
|
|
|
Combined equivalent (per Boe)
|
|
$
|
44.66
|
|
|
$
|
50.08
|
|
|
$
|
40.33
|
|
|
Average Prices - including impact of post-production expenses
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf)
|
|
$
|
0.95
|
|
|
$
|
1.71
|
|
|
$
|
2.10
|
|
|
Combined equivalent (per Boe)
|
|
$
|
44.56
|
|
|
$
|
50.00
|
|
|
$
|
40.24
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses (per Boe)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-production
|
|
$
|
0.10
|
|
|
$
|
0.08
|
|
|
$
|
0.08
|
|
|
Production taxes
|
|
$
|
2.12
|
|
|
$
|
2.39
|
|
|
$
|
1.93
|
|
|
Total expenses
|
|
$
|
2.22
|
|
|
$
|
2.47
|
|
|
$
|
2.01
|
|
|
|
(1)
|
Production volumes and related revenues and expenses
for the year ended December 31, 2019 (included in 2019 net revenue distributions to the Trust) represent production from
September 1, 2018 to August 31, 2019.
|
|
|
(2)
|
Production volumes and related revenues and expenses
for the year ended December 31, 2018 (included in 2018 net revenue distributions to the Trust) represent production from
September 1, 2017 to August 31, 2018.
|
|
|
(3)
|
Production volumes and related revenues and expenses
for the year ended December 31, 2017 (included in 2017 net revenue distributions to the Trust) represent production from
September 1, 2016 to August 31, 2017.
|
|
|
(4)
|
Barrel of oil equivalent, determined using the ratio
of six Mcf of natural gas to one Bbl of oil, which approximates the relative energy content of oil as compared to natural gas.
|
Productive Wells
The following table
sets forth as of December 31, 2019 the number of productive wells burdened by the Royalty Interests. Productive wells consist
of producing wells and wells capable of producing. Gross wells are the total number of producing wells burdened by the Royalty
Interests and net wells are the sum of the Trust’s fractional Royalty Interests owned in gross wells.
|
|
|
Oil
|
|
|
Natural Gas
|
|
|
Total
|
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Productive Wells
|
|
|
1,035
|
|
|
|
565
|
|
|
|
—
|
|
|
|
—
|
|
|
|
1,035
|
|
|
|
565
|
|
Developed and Undeveloped
Acreage
As of December 2014,
SandRidge had drilled and perforated for completion 888 equivalent Trust Development Wells, thus fulfilling its drilling obligation.
Accordingly, the AMI terminated effective December 2014, and no undeveloped acreage constituting a part of the Underlying
Properties exists.
Drilling Activity
There were no wells
drilled or completed during 2019 or 2018, and there were no wells to be drilled or awaiting completion at December 31, 2019
or 2018.
Marketing and Customers
Avalon has the responsibility
to market, or cause to be marketed, the oil, natural gas and NGL production attributable to the Underlying Properties and is not
permitted to charge any marketing fees when determining the net proceeds upon which the royalty payments are calculated, except
for marketing fees and costs of non-affiliates. SandRidge performed these services on behalf of, and in conjunction with, Avalon
during the first four months of 2019 pursuant to the terms of the transition services agreement, which terminated on April 30,
2019. As a result, the net proceeds to the Trust from the sales of oil, natural gas and NGL production from the Underlying Properties
for the years ended December 31, 2019 and 2018 are determined based on the same price (net of post-production costs) that
Avalon received for oil, natural gas and NGL production attributable to its interest in the Underlying Properties.
During each of 2019
and 2018, two customers individually accounted for more than 10% of total revenue attributable to the Royalty Interests. The number
of readily available purchasers for the production from the Underlying Properties reduces the risk that the loss of a single customer
in the area in which Avalon sells oil, natural gas and NGL production from the Underlying Properties would materially affect the
Trust’s revenue. See the table below for additional information on Avalon’s major customers for production from the
Underlying Properties from January 1, 2018 to October 31, 2019.
|
|
|
Sales
|
|
|
% of Revenue
|
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
Enterprise Crude Oil LLC
|
|
$
|
17,063
|
|
|
|
81.2
|
%
|
|
ConocoPhillips Company
|
|
$
|
3,951
|
|
|
|
18.8
|
%
|
|
2018
|
|
|
|
|
|
|
|
|
|
Enterprise Crude Oil LLC
|
|
$
|
22,685
|
|
|
|
76.0
|
%
|
|
ConocoPhillips Company
|
|
$
|
4,917
|
|
|
|
16.5
|
%
|
In October 2019,
Avalon entered into a crude oil purchasing agreement with Ace Gathering Inc., a Texas corporation doing business as Ace Energy
Solutions (“ACE”). Pursuant to the terms of the contract, Avalon is required to deliver all crude oil produced
from wells it operates, including the Underlying Properties, beginning November 1, 2019. As a result, all production from
the Underlying Properties is committed to ACE under the contract through December 31, 2021. The price for each barrel of crude
oil delivered under the contract is NYMEX West Texas Intermediate averaged over the month of delivery, subject to certain adjustments
as set forth in the contract. Avalon entered into this contract, together with an agreement whereby Avalon can purchase condensate
from ACE to use in its well workover program, in order to maximize the price of production, as well as the transparency of pricing,
from the Underlying Properties and other properties operated by Avalon. Transportation of crude oil sold by Avalon will continue
to utilize existing pipeline systems and suppliers, including Enterprise Crude Oil LLC and ConocoPhillips Company.
Title to Properties
The Underlying Properties
are subject to certain burdens that are described in more detail below. To the extent that these burdens and obligations affect
the rights of Avalon in production and the value of production from the Underlying Properties, they have been taken into account
in calculating the Trust’s interest and in estimating the size and value of the reserves attributable to the Royalty Interests.
The Underlying Properties are typically subject, in one degree or another, to one or more of the following:
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•
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royalties and other burdens, express and implied, under oil and natural gas leases;
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•
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production payments and similar interests and other burdens created by Avalon’s predecessors
in title;
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•
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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 titles;
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•
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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;
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•
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pooling, unitization and communitization agreements, declarations and orders;
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•
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easements, restrictions, rights-of-way and other matters that commonly affect real property;
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•
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conventional rights of reassignment that obligate Avalon to reassign all or part of a property
to a third party if Avalon intends to release or abandon such property; and
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•
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rights reserved to or vested in the appropriate governmental agency or authority to control or
regulate the Underlying Properties.
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Avalon believes that its title to the Underlying
Properties and the Trust’s title to the Royalty Interests are good and defensible in accordance with standards generally
accepted in the oil and natural gas industry, subject to such exceptions as are not so material as to detract substantially from
the use or value of such properties or Royalty Interests.
Competition and Markets
The production and
sale of oil, natural gas and NGL is highly competitive. Competitors in the Permian Basin include major oil and gas companies, independent
oil and gas companies, and individual producers and operators. There are numerous producers in the Permian Basin, and competitive
position in this area is affected by price, contract terms and quality of service.
Oil, natural gas and
NGL 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, natural gas and NGL.
Future price fluctuations
for oil, natural gas and NGL will directly impact Trust distributions, estimates of reserves attributable to the Royalty Interests
and estimated and actual future net revenues to the Trust. Due to the many uncertainties that affect the supply and demand for
oil, natural gas and NGL, reliable predictions of future oil, natural gas and NGL supply and demand, future product prices or the
effect of future product prices on Trust distributions cannot be made. However, lower production volumes and product prices will
adversely affect Trust distributions.
Seasonal Nature of Business
Generally, demand
for oil, natural gas and NGL decreases during the summer months and increases during the winter months. Certain natural gas users
utilize natural gas storage facilities and purchase some of their anticipated winter requirements during the summer, which can
lessen seasonal demand fluctuations. Seasonal weather conditions and lease stipulations can limit producing activities and other
oil and natural gas operations. These seasonal anomalies can increase competition for equipment, supplies and personnel during
the spring and summer months, which could lead to shortages and increased costs or delay operations.
Insurance
Avalon operates all
of the wells burdened by the Royalty Interests. Avalon maintains insurance, in accordance with industry practice, against some,
but not all, of the operating risks to which its operating affiliate is exposed. Generally, insurance policies include coverage
for general liability (including sudden and accidental pollution), physical damage to certain oil and natural gas properties, auto
liability, worker’s compensation and employer’s liability, among other things.
Avalon maintains general
liability insurance coverage up to $1 million per occurrence and $2 million aggregate policy limit, which includes (i) completed
operations coverage and (ii) sudden and accidental environmental liability coverage for the effects of pollution on third
parties, arising from operations. The general liability insurance policy contains limits subject to certain customary exclusions
and limitations, as well as deductibles that must be met prior to recovery. In addition, Avalon maintains $25 million in excess
liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached, and may be
subject to a deductible that must be met prior to recovery. Avalon also maintains worker’s compensation coverage in accordance
with Texas statutory requirements and employee liability coverage of $1 million by accident or by disease.
All of Avalon’s
third-party contractors are required to sign master services agreements in which they agree (a) to indemnify Avalon for injuries
and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider and
(b) name Avalon as an additional insured on their insurance policies. Similarly, Avalon generally agrees to indemnify each
third-party contractor against claims made by employees of Avalon and Avalon’s other contractors. Additionally, each party
generally is responsible for damage to its own property.
The third-party contractors
that perform hydraulic fracturing operations sign the master services agreements containing the indemnification provisions noted
above. Currently there are no insurance policies in effect intended to provide coverage for losses solely related to hydraulic
fracturing operations as none have been performed by Avalon on the Underlying Properties or other properties owned by Avalon.
Avalon annually re-evaluates
the purchase of insurance, coverage limits and deductibles. Future insurance coverage for the oil and natural gas industry could
increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable
in the future or unavailable on terms that are economically acceptable. No assurance can be given that insurance may be maintained
in the future at rates considered reasonable. Self-insurance or only catastrophic coverage may be elected for certain risks in
the future.
The Trust does not
maintain any insurance policies or coverage against any of the risks of conducting oil and gas exploration and production or related
activities.
Regulation
Oil and Natural
Gas Regulations. The oil and natural gas industry is extensively regulated by numerous federal, state, local and regional authorities,
as well as Native American tribes. Legislation affecting the oil and natural gas industry is under constant review for amendment
or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, and
Native American tribes are authorized by statute to issue rules and regulations affecting the oil and natural gas industry
and its individual members, some of which carry substantial penalties for noncompliance. Although the regulatory burden on the
oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability, these burdens generally
do not affect SandRidge or Avalon any differently or to any greater or lesser extent than they affect other companies in the industry
with similar types, quantities and locations of production.
The availability,
terms and cost of transportation significantly affect sales of oil, natural gas and NGL. The interstate transportation and sale
for resale of oil, natural gas and NGL is subject to federal regulation, including regulation of the terms, conditions and rates
for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”).
Federal and state regulations govern the price and terms for access to oil and natural gas pipeline transportation. FERC’s
regulations for interstate oil and natural gas transmission in some circumstances may also affect the intrastate transportation
of oil and natural gas.
However, sales of
oil, natural gas and NGL produced from the Underlying Properties are not currently regulated and are transacted at market prices.
Although oil, natural gas and NGL prices are currently unregulated, Congress historically has been active in the area of oil and
natural gas regulation. Whether new legislation to regulate oil, natural gas and NGL prices might be proposed, what proposals,
if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have
on the operations of the Underlying Properties cannot be predicted.
Production.
Operations are subject to various types of regulation at federal, state and local levels. These types of regulation include reports
concerning operations. Most states, and some counties, municipalities and Native American tribal areas also regulate one or more
of the following activities: the rates of production, or “allowables”, the use of surface or subsurface waters, the
surface use and restoration of properties upon which wells are drilled, the plugging and abandoning of wells, and the notice to
surface owners and other third parties.
State laws regulate
the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some
states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of
lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce Avalon’s
interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural
gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil, natural gas and NGL production from its wells or limit the number of wells
or the locations which can be drilled. Moreover, each state generally imposes a production or severance tax with respect to the
production and sale of oil, natural gas and NGL within its jurisdiction.
Federal, state and
local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities
and pipelines, and for site restorations, in areas where the Underlying Properties are located. For example, the Railroad Commission
of Texas imposes financial assurance requirements on operators, and the United States Army Corps of Engineers (“ACE”)
and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration.
Natural Gas Sales and Transportation.
Historically, federal
legislation and regulatory controls have affected the price of the natural gas Avalon produces and the manner in which Avalon markets
its production. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural
gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Various federal laws enacted since 1978
have resulted in the removal of all price and non-price controls for sale of domestic natural gas sold in first sales, which include
all of Avalon’s sales of from the Underlying Properties. Under the Energy Policy Act of 2005, FERC has substantial enforcement
authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess
substantial civil penalties.
FERC also regulates
interstate natural gas transportation rates and service conditions and establishes the terms under which Avalon may use interstate
natural gas pipeline capacity, which affects the marketing of natural gas produced from the Underlying Properties, as well as the
revenues it receives for sales of its natural gas and release of its natural gas pipeline capacity. Commencing in 1985, FERC promulgated
a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and
marketing gas. Currently, interstate pipeline companies are required to provide nondiscriminatory transportation services to producers,
marketers and other shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s
initiatives have led to the development of a competitive, open access market for natural gas purchases and sales that permits all
purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry
historically has been very heavily regulated; therefore, the less stringent regulatory approach currently pursued by FERC and Congress
might not continue indefinitely into the future. Avalon is not able to determine what effect, if any, future regulatory changes
might have on future natural gas related activities with respect to the Underlying Properties.
Under FERC’s
current regulatory regime, transmission services must be provided on an open-access, nondiscriminatory basis at cost-based rates
or at market-based rates if the transportation market at issue is sufficiently competitive. Gathering service, which occurs upstream
of jurisdictional transmission services, is regulated by the states – in the case of Texas by the Railroad Commission of
Texas. Although its policy is still in flux, in the past FERC has reclassified certain jurisdictional transmission facilities as
non-jurisdictional gathering facilities, which has the tendency to increase the cost of transporting gas to point-of-sale locations.
Oil Price Controls
and Transportation Rates.
Sales prices of oil
and NGL produced from the Underlying Properties are not currently regulated and are made at market prices. Sales of these commodities
are, however, subject to laws and to regulations issued by the Federal Trade Commission (the “FTC”) prohibiting
manipulative or fraudulent conduct in the wholesale petroleum market. The FTC holds substantial enforcement authority under these
regulations, including the ability to assess substantial civil penalties.
The price received
from the sale of these products may be affected by the cost of transporting the products to market. Some transportation of oil,
natural gas and NGL is through interstate common carrier pipelines. Effective as of January 1, 1995, FERC implemented regulations
generally grandfathering all previously approved interstate transportation rates and establishing an indexing system for those
rates by which adjustments are made annually based on the rate of inflation, subject to certain conditions and limitations. FERC’s
regulation of crude oil and natural gas liquids transportation rates may tend to increase the cost of transporting crude oil and
natural gas liquids by interstate pipelines, although the annual adjustments may result in decreased rates in a given year. Every
five years, FERC must examine the relationship between the annual change in the applicable index and the actual cost changes experienced
in the oil pipeline industry. Avalon is not able at this time to predict the effects of these regulations or FERC proceedings,
if any, on the transportation costs associated with crude oil producing operations.
Environmental and
Occupational Safety and Health Regulation. Oil, natural gas and NGL exploration, development and production operations are
subject to stringent and complex federal, state, tribal, regional and local laws and regulations governing worker safety and health,
the discharge and disposal of substances into the environment, and the protection of the environment and natural resources. Numerous
governmental entities, including the U.S. Environmental Protection Agency (“EPA”), the Occupational Safety and
Health Administration (“OSHA”), ACE, and analogous state and local agencies (and, under certain laws, private
individuals), have the power to enforce compliance with these laws and regulations and any permits issued under them. These laws
and regulations may, among other things: (i) require permits to conduct exploration, drilling, water withdrawal, wastewater
disposal and other production related activities; (ii) govern the types, quantities and concentrations of substances that
may be disposed or released into the environment or injected into formations in connection with drilling or production activities,
and the manner of any such disposal, release or injection; (iii) limit or prohibit construction or require formal mitigation
measures in sensitive areas such as wetlands, wilderness areas or areas inhabited by endangered or threatened species; (iv) require
investigatory and remedial actions to mitigate pollution conditions arising from or attributable to former operations of the Underlying
Properties; (v) impose safety and health restrictions designed to protect employees from exposure to hazardous or dangerous
substances; and (vi) impose obligations to reclaim and abandon well sites and pits. Failure to comply with these laws and
regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of
investigatory, remedial or corrective action obligations, the occurrence of delays or restrictions in permitting or performance
of projects and the issuance of orders enjoining operations in affected areas.
Since taking office,
the Trump Administration has taken steps aimed at reducing federal regulatory burdens and costs for the oil and gas industry. Nevertheless,
changes in environmental regulation may place more restrictions and limitations on activities that may affect the environment.
Any changes in or more stringent enforcement of these laws and regulations that result in delays or restrictions in permitting
or development of projects, or more stringent or costly construction, drilling, water management or completion activities or waste
handling, storage, transport, remediation, or disposal, emission or discharge requirements could have a material adverse effect
on the Trust’s revenues. Moreover, accidental releases, including spills, may occur in the course of operations on the Underlying
Properties, and significant costs could be incurred as a result of such releases or spills, including third-party claims for damage
to property and natural resources or personal injury. While Avalon believes that compliance with existing environmental laws and
regulations and that continued compliance with existing requirements will not materially affect operation of the Underlying Properties,
it is possible that Avalon may incur substantial costs in the future related to revised or additional environmental regulations
that could have a material adverse effect on its business, financial condition, and results of operations.
The following is a
summary of the more significant existing and proposed environmental and occupational safety and health laws and regulations, as
amended from time to time, to which the Underlying Properties and Avalon's business operations are subject and for which compliance
may have a material adverse impact on the Trust or operation of the Underlying Properties.
Hazardous Substances
and Wastes. The federal Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”)
and comparable state laws may impose strict, joint and several liability, without regard to fault or legality of conduct on certain
persons who are responsible for the release of a “hazardous substance” into the environment. These persons include
current and prior owners or operators of the site where the release of a hazardous substance occurred as well as entities that
disposed or arranged for the disposal of the hazardous substance released at the site. Under CERCLA, these “responsible parties”
may be liable for the costs of cleaning up sites where hazardous substances have been released into the environment, for damages
to natural resources resulting from the release and for the costs of certain environmental and health studies. Additionally, landowners
and other third parties may file claims for personal injury and natural resource and property damage allegedly caused by the release
of hazardous substances into the environment. CERCLA also authorizes the EPA and, in some instances, third parties to act in response
to threats to the public health or the environment from a hazardous substance release and to pursue steps to recover costs incurred
for those actions from responsible parties. Despite the so-called “petroleum exclusion,” certain products used by Avalon
and used previously by SandRidge in the course of operations at the Underlying Properties may be regulated as CERCLA hazardous
substances. To date, none of the Underlying Properties have been subject to CERCLA response actions.
The federal Resource
Conservation and Recovery Act (“RCRA”) and comparable state statutes and implementing regulations impose strict
“cradle-to-grave” requirements on the generation, transportation, treatment, storage and disposal and cleanup of hazardous
and non-hazardous wastes. SandRidge, Avalon and any other operators of the Underlying Properties have and will generate wastes
that are subject to the requirements of RCRA and comparable state statutes. Drilling fluids, produced waters and other wastes associated
with the exploration, production and/or development of oil and natural gas, including naturally-occurring radioactive material,
if properly handled, are currently excluded from regulation as hazardous wastes under RCRA and, instead, are regulated under RCRA’s
less stringent non-hazardous waste requirements. However, it is possible that these wastes could be classified as hazardous wastes
in the future. For example, in December 2016, the EPA and environmental groups entered into 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 requires 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. Any future change in the exclusion
for such wastes could potentially result in an increase in the cost of managing and disposing of those wastes.
Air Emissions and
Climate Change. The federal Clean Air Act, as amended (“CAA”), and comparable state laws and regulations
restrict the emission of air pollutants through emissions standards, construction and operating permitting programs, and the imposition
of other compliance requirements. These laws and regulations may require pre-approval for the construction or modification of certain
projects or facilities expected to produce or significantly increase air emissions, strict compliance with air permit requirements
or the utilization of specific equipment or technologies to control emissions. The need to acquire such permits has the potential
to delay or limit the development of oil and natural gas projects or require Avalon to incur certain capital expenditures for air
pollution control equipment or other air emissions-related issues.
Furthermore, in 2009,
the EPA published its findings that emissions of carbon dioxide, methane and certain other “greenhouse gases” (collectively,
“GHGs”) present an endangerment to public health and the environment because emissions of such gases are, according
to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. The EPA has taken a number of steps
aimed at gathering information about, and reducing the emissions of, GHGs from industrial sources, including oil and natural gas
sources. The EPA has adopted rules requiring the reporting of GHG emissions from oil, natural gas and NGL production and processing
facilities on an annual basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and
workovers using hydraulic fracturing. The EPA also has adopted and implemented regulations under existing provisions of the CAA
that, among other things, establish Prevention of Significant Deterioration (“PSD”) construction 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. This rule could
adversely affect Avalon’s operations upon the Underlying Properties and restrict or delay its ability to obtain air permits
for new or modified facilities that exceed GHG emission thresholds.
In 2012, the EPA published
a final rule adopting 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 is 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 adopting additional NSPS
requirements for new, modified, or reconstructed oil and gas facilities that require control of the greenhouse gas methane from
affected facilities, including requirements to find and repair fugitive leaks of methane emissions at well sites (“Methane
Rule”). 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 (the “BLM Methane and Waste Prevention Rule”) that are substantially similar to the EPA’s
Methane Rule.
The EPA also is charged
with establishing ambient air quality standards, the implementation of which can indirectly impact Avalon’s operations. For
example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”), for ozone
from 75 to 70 parts per billion. Although the EPA has designated all counties in which the Underlying Properties are located as
attainment areas for the 2015 ozone standard, these determinations may be revised in the future. State implementation of the revised
NAAQS could result in stricter permitting requirements, delay or prohibit Avalon’s ability to obtain such permits, and result
in increased expenditures for pollution control equipment, the costs of which could be significant.
Following the 2016
presidential election and change in administrations, President Trump signed Executive Order 13783 directing federal agencies to
review and, if appropriate, revise all existing regulations “that potentially burden the development or use of domestic energy
resources, with particular attention to oil and gas.” Pursuant to the Executive Order, the BLM and EPA commenced reviews
of the BLM Methane and Waste Prevention Rule and the oil and gas NSPS, respectively. In December 2017, the BLM published
a final rule to temporarily suspend or delay certain requirements contained in the November 2016 final rule until
January 17, 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 revising or rescinding certain provisions of the BLM Methane
and Waste Prevention Rule. This action has been challenged by the states of California and New Mexico, as well as environmental
groups, in the Northern District of California. Such litigation is still pending. Separately, the EPA’s review of its regulations
resulted in (a) then EPA Administrator Scott Pruitt withdrawing the request for information needed to develop emissions guidelines
for existing facilities in March, 2017, (b) a proposal to delay implementation of the Methane Rule, and (c) the convening
of a reconsideration proceeding that resulted in two 2018 rulemaking projects aimed at rolling back certain Methane Rule requirements.
In August 2019, the EPA proposed amendments to the Methane Rule aimed at eliminating federal requirements that oil and
gas companies install technology to detect and fix methane leaks from wells, pipelines and storage facilities, while maintaining
the rule’s substantive emissions control requirements because they serve to control emissions of other, non-methane pollutants..
The ultimate fate of the Methane Rule requirements is unclear. Nevertheless, regulations promulgated under the CAA may require
Avalon to incur expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its
operations.
The Congressional
reaction to the BLM and EPA action has been mixed, but there seems to be growing support, at least in the House of Representatives,
in support for maintaining and potentially strengthening methane regulation. During the current Congressional session, five bills
have been introduced which, if enacted, would codify existing methane regulations and/or force additional regulatory action. Examples
include the Super Pollutants Act (H.R. 4143), which would codify the oil and gas NSPS and require the EPA to develop emissions
guidelines for existing oil and gas facilities within two years, and the CLEAN Future Act which aims to achieve a 100% clean economy
by not later than 2050 including a plan to achieve “net zero” GHGs.
Although future federal
GHG regulations for the oil and gas industry remain a possibility given the long-term trend towards increasing regulation, the
form of these regulations remains uncertain as the Trump administration has made it clear they will oppose any such regulation.
Moreover, several states have already adopted rules requiring operators of both new and existing oil and gas facilities to
develop and implement leak detection and repair (“LDAR”) program and to install devices on certain equipment
to capture 95% of methane emissions. Compliance with these rules could require Avalon to purchase pollution control equipment
and optical gas imaging equipment for LDAR inspections, and to hire additional personnel to assist with inspection and reporting
requirements.
Compliance with these
and other air pollution control and permitting requirements has the potential to increase Avalon’s production costs, which
costs could be significant. Additionally, violations of lease conditions or regulations related to air emissions can result in
civil and criminal penalties, as well as potential court injunctions curtailing operations and canceling leases. Such enforcement
liabilities can result from either governmental or citizen enforcement.
Water Discharges.
The federal Clean Water Act (“CWA”) and analogous state laws and implementing regulations impose restrictions
and strict controls regarding the discharge of pollutants into waters of the United States and waters of the states, respectively.
Pursuant to these laws and regulations, the discharge of pollutants to regulated waters is prohibited unless it is permitted by
the EPA, ACE or an analogous state agency. The discharge of wastewater from most onshore oil and gas exploration and production
activities is currently prohibited east of the 98th meridian. Additionally, in June 2016, the EPA issued a final
rule implementing wastewater pre-treatment standards that prohibit onshore unconventional oil and natural gas extraction facilities
from sending wastewater directly to publicly owned treatment works (“POTW”). Unconventional extraction facilities
are in certain circumstances allowed by federal regulations to send wastewater to an off-site private centralized wastewater treatment
facility that can either discharge treated water or send it to a POTW. The EPA is conducting a study of the treatment and discharge
of oil and gas wastewater. Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge
requirements may result in increased costs. Avalon does not presently discharge pollutants associated with the exploration, development
and production of oil, natural gas and NGL on the Underlying Properties into federal or state waters. Rather, it disposes of such
fluids by regulated injection into salt water disposal wells located on the Underlying Properties in compliance with the Underground
Injection Control program described below.
How the EPA and the
ACE define “waters of the United States” (“WOTUS”) can impact Avalon’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 recodified
longstanding regulatory definitions of WOTUS that existed prior to the 2015 rule to promote regulatory consistency across
the United States. On February 14, 2019, EPA and the ACE had published a proposed revised definition of WOTUS intended to
clarify and narrow the definition from that in the 2015 rule. The comment period on the proposed changes to the definition of WOTUS
closed on April 15, 2019, and a final rule is expected to be published in early 2020. It is anticipated that petitions
for review of any 2020 WOTUS rule will be filed and that litigation over the definition of WOTUS will continue. To the extent
that Avalon must obtain permits for the discharge of pollutants or for dredge and fill activities in wetland areas or other waters
of the United States, Avalon could face increased costs and delays associated with obtaining such permits under any broader definition
of WOTUS that expands the scope of CWA jurisdiction.
Finally, the Oil Pollution
Act of 1990 (“OPA”), which amends the CWA, establishes standards for prevention, containment and cleanup of
oil spills into waters of the United States. The OPA requires measures to be taken to prevent the accidental discharge of oil into
waters of the United States from onshore production facilities. Measures under the OPA and/or the CWA include: inspection and maintenance
programs to minimize spills from oil storage and conveyance systems; the use of secondary containment systems to prevent spills
from reaching nearby waterbodies; proof of financial responsibility to cover environmental cleanup and restoration costs that could
be incurred in connection with an oil spill; and the development and implementation of spill prevention, control and countermeasure
(“SPCC”) plans to prevent and respond to oil spills. The OPA also subjects owners and operators of facilities
to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a spill. SandRidge
has developed and implemented SPCC plans for the Underlying Properties as required under the CWA, and Avalon is continuing to administer
these SPCC plans.
Subsurface Injections.
Any underground injection operations that may be performed by Avalon in the future are subject to the Safe Drinking Water Act
(“SDWA”), as well as analogous state laws and regulations. Under the SDWA, the EPA established the Underground
Injection Control (“UIC”) program, which established the minimum program requirements for state and local programs
regulating underground injection activities. The UIC program includes requirements for permitting, testing, monitoring, record
keeping and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant
into underground sources of drinking water. Texas state regulations require a permit from the Railroad Commission of Texas to operate
underground injection wells. Avalon has obtained such UIC permits. Although Avalon monitors the injection process of its injectionl
wells, any leakage from the subsurface portions of such wells could cause degradation of fresh groundwater resources, potentially
resulting in suspension of Avalon’s UIC permit, issuance of fines and penalties from governmental agencies, incurrence of
expenditures for remediation of the affected resource and imposition of liability by third-parties claiming damages for alternative
water supplies, property damages and personal injuries. Some states have considered laws mandating flowback and produced water
recycling. Other states, including Texas, have undertaken studies to assess the feasibility of recycling produced water on a large
scale. For example, in July 2018, the EPA partnered with New Mexico to evaluate alternatives to injection of wastewater from
exploration and production activities by reusing it or treating it for reintroduction into the hydrologic cycle or both, and to
propose potential regulations related thereto. If laws mandating reuse and/or treatment in lieu of injection are adopted for the
counties in which the Underlying Properties are located, Avalon’s operating costs may increase significantly.
Endangered Species.
The federal Endangered Species Act (“ESA”) restricts activities that may affect endangered or threatened
species or their habitats without first obtaining an incidental take permit and implementing mitigation measures. Similar protections
are offered to migratory birds under the federal Migratory Bird Treaty Act. If endangered species are located in areas of the Underlying
Properties where seismic surveys, development activities or abandonment operations may be conducted, the work could be prohibited
or delayed or expensive mitigation may be required. In February 2016, the U.S. Fish and Wildlife Service (“USFWS”)
published a final policy which alters how it identifies critical habitat for endangered and threatened species. On August 27,
2019, the USFWS published a final rule adopting several changes to ESA regulations, 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. A critical habitat designation could result in further material restrictions to federal and private land use and could
delay or prohibit land access or development. The designation of previously unprotected species as threatened or endangered in
areas where operations on the Underlying Properties are located could cause Avalon to incur increased 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 Avalon are subject to a number of federal and state laws and regulations, including the federal
Occupational Safety and Health Act and comparable state statutes, whose purpose is to protect the health and safety of workers.
In addition, the Hazard Communication Standard implemented by OSHA requires Avalon to maintain information concerning hazardous
materials used or produced in its operations and to provide this information to employees. Pursuant to the Federal Emergency Planning
and Community Right-to-Know Act, facilities that store hazardous chemicals that are subject to OSHA’s Hazard Communication
Standard above certain threshold quantities must submit information regarding those chemicals by March 1 of each year to state
and local authorities in order to facilitate emergency planning and response. That information is generally available to employees,
state and local governmental authorities, and the public. Avalon has been and is submitting this information to these authorities
for the Underlying Properties.
Item 1A.
Risk Factors
Risks
Related to the Trust Units
Producing oil,
natural gas and NGL from the Underlying Properties is a high risk activity with many uncertainties that could adversely affect
future production from the Underlying Properties. Any such reductions in production could decrease cash that is available for distribution
to unitholders.
Production operations
on the Underlying Properties may be curtailed, delayed or canceled as a result of various factors, including the following:
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reductions in oil, natural gas and NGL prices;
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unusual or unexpected geological formations and miscalculations;
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equipment malfunctions, failures or accidents;
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lack of available gathering facilities or delays in construction of gathering facilities;
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ack of available capacity on interconnecting transmission pipelines;
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lack of adequate electrical infrastructure and water disposal capacity;
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unexpected operational events;
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pipe or cement failures and casing collapses;
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pressures, fires, blowouts and explosions;
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uncontrollable flows of oil, NGL, natural gas, brine, water or drilling fluids;
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environmental hazards, such as oil spills, natural gas and NGL leaks, pipeline or tank ruptures,
encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids,
toxic gases or other pollutants into the surface and subsurface environment;
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high costs, shortages or delivery delays of equipment, labor or other services, or water used in
hydraulic fracturing;
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compliance with environmental and other governmental requirements;
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adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain
and severe storms or tornadoes; and
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market limitations for oil, natural gas and NGL.
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If production from the Trust wells is lower
than anticipated due to one or more of the foregoing factors or for any other reason, cash distributions to Trust unitholders may
be reduced.
Oil, natural
gas and NGL prices can fluctuate widely due to a number of factors that are beyond the control of the Trust and Avalon. Continued
volatility in oil, natural gas or NGL prices could reduce proceeds to the Trust and cash distributions to unitholders.
The value of the petroleum
reserves attributable to the Royalty Interests and the amount of revenue available for quarterly cash distributions to Trust unitholders
are highly dependent upon the prices realized from the sale of oil, natural gas and NGL produced from the Underlying Properties.
Historically, the markets for these hydrocarbons have been very volatile. Prices for oil, natural gas and NGL can move quickly
and fluctuate widely in response to a variety of factors that are beyond the control of the Trust or Avalon. These factors include,
among others:
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changes in regional, domestic and foreign supply of, and demand for, oil, natural gas and NGL,
as well as perceptions of supply of, and demand for, oil, natural gas and NGL generally;
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the price and quantity of foreign imports;
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the ability of other companies to complete and commission liquefied natural gas export facilities
in the U.S.;
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U.S. and worldwide political and economic conditions;
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the occurrence or threat of epidemic or pandemic diseases, including the recent outbreak of coronavirus,
or any government response to such occurrence or threat;
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weather conditions and seasonal trends;
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future prices of oil, natural gas and NGL, alternative fuels and other commodities;
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technological advances affecting energy consumption and energy supply;
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the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation
and refining capacity;
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natural disasters and other extraordinary events;
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domestic and foreign governmental regulations and taxation;
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energy conservation and environmental measures; and
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the price and availability of alternative fuels.
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These factors and the volatility of the
energy markets, which is expected to continue, make it extremely difficult to predict future oil, natural gas and NGL price movements
with any certainty. For crude oil, from January 2018 through December 2019, the highest spot price for West Texas Intermediate
(WTI) was $76.41 per Bbl and the lowest was $42.53 per Bbl. For natural gas, from January 2018 through December 2019,
the highest Henry Hub natural gas spot price was $4.25 per MMBtu and the lowest was $1.75 per MMBtu. In addition, the market price
of oil and natural gas is generally lower in the summer months than during the winter months of the year due to decreased demand
for oil and natural gas for heating purposes during the summer season.
Oil, natural gas
and NGL prices experienced substantial fluctuations during 2019 ending the year at $61.06/Bbl (spot price for WTI crude oil),
or up approximately 31.2% from the January 2, 2019 spot price of $46.54/Bbl. A buildup in inventories, lower global
demand, or other factors, including one or more factors listed above, have caused prices for U.S. oil to weaken further, and
could result in additional declines from current levels. The spot price for WTI crude oil has decreased a further 50.6% from $61.17
on January 2, 2020 to $30.24 on March 9, 2020. Continued low oil, natural gas and NGL prices will reduce proceeds
to which the Trust is entitled and may ultimately reduce the amount of oil, natural gas and NGL that is economic to produce
from the Underlying Properties causing the Trust to make substantial downward adjustments to its estimated proved reserves.
As a result, Avalon could determine during periods of low oil, natural gas or NGL prices to shut in or curtail production
from wells that are not producing in paying quantities (using the Reasonably Prudent Operator Standard) on the Underlying
Properties. Furthermore, pursuant to the terms of the Conveyances, Avalon has the right to abandon, at its cost, any well if
it reasonably believes that the well can no longer produce oil, natural gas and NGL in paying quantities. This could result
in termination of the portion of the Royalty Interest relating to the abandoned well, and Avalon has no obligation to drill a
replacement well.
Actual petroleum
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 estimated to be attributable to the Royalty Interests. It is not possible to accurately measure underground accumulations
of oil, natural gas and NGL in an exact way and estimating reserves is inherently uncertain. As discussed below, the process of
estimating oil, natural gas and NGL reserves requires interpretations of available technical data and many assumptions. Any significant
inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of the
reserves attributable to the Royalty Interests. This could result in actual production and revenues for the Underlying Properties
being materially less than estimated amounts.
In order to prepare the estimates of reserves
attributable to the Underlying Properties and the Royalty Interests, production rates must be projected. In so doing, available
geological, geophysical, production and engineering data must be analyzed. The extent, quality and reliability of this data can
vary. In addition, petroleum engineers are required to make subjective estimates of underground accumulations of oil, natural gas
and NGL 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, natural gas and NGL prices, production levels, Btu content, production expenses, transportation
costs, severance and excise taxes and capital expenditures; and
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the assumed effect of governmental regulation.
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A material and adverse variance of actual
production, revenues and expenditures from those underlying reserve estimates would have a material adverse effect on the financial
condition, results of operations and cash flows of the Trust and would reduce cash distributions to Trust unitholders. As a result,
the Trust may not receive the benefit of the total amount of reserves reflected in the reserve report.
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 New York Stock Exchange (“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 December 27,
2019, 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, and neither the Trust nor the Trustee
intends to attempt to cause a reverse split of the Trust units or other action in an effort to affect the trading price of the
Trust units. Even if the Trust does regain compliance, it might be unable to maintain compliance, and would again become subject
to the NYSE delisting procedures.
Production of
oil, natural gas and NGL on the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.
Production of oil,
natural gas and NGL on the Underlying Properties could be materially and adversely affected by severe weather. Repercussions of
severe weather conditions may include:
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changes in oil viscosity as a result of extremely cold weather conditions;
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evacuation of personnel and curtailment of operations;
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weather-related damage to facilities, resulting in suspension of operations;
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inability to deliver materials to worksites; and
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weather-related damage to pipelines and other transportation facilities.
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Interruptions in production
could have a material adverse effect on the Trust’s financial condition, results of operations and cash flows, and could
reduce the amount of cash distributions to unitholders.
Due to the Trust’s
lack of industry and geographic diversification, adverse developments in the location of the Underlying Properties could adversely
impact the Trust’s financial condition, results of operations and cash flows and reduce its ability to make distributions
to the Trust unitholders.
The Underlying Properties
are being and will be operated for oil, natural gas and NGL production only and are focused exclusively in the Permian Basin in
Andrews County, Texas. This concentration could disproportionately expose the Trust’s interests to operational and regulatory
risk in that area. Due to the lack of diversification in industry type and location of the Trust’s interests, adverse developments
in the oil and natural gas market or the area of the Underlying Properties, including, for example, transportation or treatment
capacity constraints, curtailment of production or treatment plant closures for scheduled maintenance, could have a significantly
greater impact on the Trust’s financial condition, results of operations and cash flows than if the Royalty Interests were
more diversified.
The generation
of proceeds for distribution by the Trust depends in part on Avalon’s access to and the operation of gathering, transportation
and processing facilities. Limitations in the availability of those facilities could interfere with sales of oil, natural gas and
NGL production from the Underlying Properties.
The amount of oil,
natural gas and NGL that may be produced and sold from any well to which the Underlying Properties relate is subject to (a) curtailment
of production in certain circumstances, such as by reason of weather, pump failure, down-hole issues or other operating risks common
to the production of hydrocarbons, and (b) the availability of adequate transportation services or the curtailment of transportation
services, including pipeline interruptions due to scheduled and unscheduled maintenance, failure of tendered oil, natural gas and
NGL 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, Avalon is provided limited notice, if any, as to when production will
be curtailed and the duration of such curtailments. If Avalon is forced to reduce production due to such a curtailment or other
interruption of transportation services, the revenues of the Trust and the amount of cash distributions to the Trust unitholders
would similarly be reduced due to the reduction of proceeds from the sale of production.
The Trust is passive in nature and has no voting rights
in Avalon, no managerial, contractual or other ability to influence Avalon, and no right to exercise control over the field operations
of, or sale of oil, natural gas and NGL from, the Underlying Properties.
Neither the Trust
nor any Trust unitholder has any voting rights with respect to Avalon and, therefore, has no managerial, contractual or other ability
to influence Avalon’s activities or operations of the Underlying Properties. In addition, some of the Underlying Properties
may, in the future, be operated by third parties unrelated to Avalon. Such third-party operators may not have the operational expertise
of Avalon. Oil and natural gas properties are typically managed pursuant to an operating agreement among the working interest owners
in the properties. The typical operating agreement contains procedures whereby the owners of the aggregate working interest 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 sale of production, compliance with regulatory requirements and other
matters that affect the property. The failure of an operator to adequately perform operations could reduce production from the
Underlying Properties and cash available for distribution to unitholders. Neither the Trustee nor the Trust unitholders has any
contractual or other ability to influence or control the field operations of, sale of oil, natural gas and NGL from, or future
development of, the Underlying Properties.
The oil, natural
gas and NGL reserves estimated to be attributable to the Royalty Interests 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 royalty interests
to replace the depleting assets and production.
The proceeds payable
to the Trust from the Royalty Interests are derived from the sale of oil, natural gas and NGLs produced from the Underlying Properties.
The oil, natural gas and NGL reserves attributable to the Royalty Interests are depleting assets, which means that the reserves
of oil, natural gas and NGL attributable to the Royalty Interests will decline over time as will the quantity of oil, natural gas
and NGL produced from the Underlying Properties.
Future maintenance
of the wells burdened by the Royalty Interests may affect the quantity of proved reserves that can be economically produced from
the Underlying Properties. The timing and size of these projects will depend on, among other factors, the market prices of oil,
natural gas and NGL. Pursuant to the terms of the Conveyances, Avalon is obligated to operate and maintain the Underlying Properties
in good faith and in accordance with the Reasonably Prudent Operator Standard. However, Avalon has no contractual obligation to
make capital expenditures on the Underlying Properties in the future. If Avalon does not implement maintenance projects when warranted,
the future rate of production decline of proved reserves may be higher than the rate currently expected by Avalon or estimated
in the Trust’s reserve report.
The Trust Agreement
generally limits the Trust’s business activities to owning the Royalty Interests and activities reasonably related to such
ownership, including activities required or permitted by the terms of the Conveyances related to the Royalty Interests. As a result,
the Trust is not permitted to acquire other oil and natural gas properties or royalty interests to replace the depleting assets
(the Underlying Properties) and production attributable thereto.
An increase
in the differential between the price realized by Avalon for oil and natural gas produced from the Underlying Properties and the
NYMEX or other benchmark price of oil or natural gas could reduce the proceeds to the Trust and therefore the cash distributions
by the Trust and the value of Trust units.
The prices received
for oil and natural gas production usually fall below benchmark prices such as NYMEX. The difference between the price received
and the benchmark price is called a differential. The amount of the differential depends on a variety of factors, including discounts
based on the quality and location of hydrocarbons produced, Btu content and post-production costs, including transportation. These
factors can cause differentials to be volatile from period to period. Sellers of production have little or no control over the
factors that determine the amount of the differential, and cannot accurately predict differentials for natural gas or crude oil.
Increases in the differential between the realized price of oil or natural gas and the benchmark price for oil or natural gas in
the area where the Underlying Properties are located (Andrews County, Texas) could reduce the proceeds to the Trust and therefore
the cash distributions made by the Trust and the value of the Trust units. Due to the cost of transportation in the Permian Basin
(in part caused by a lack of pipeline capacity in certain fields), the differential may fluctuate significantly from period to
period.
The amount of
cash available for distribution by the Trust is reduced by Trust expenses, post-production costs and applicable taxes associated
with the Royalty Interests.
The Royalty Interests
and the Trust bear certain costs and expenses that reduce the amount of cash received by or available for distribution by the Trust
to the Trust unitholders. These costs and expenses include the following:
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the Trust’s share of the costs incurred by Avalon to gather, store, compress, transport,
process, treat, dehydrate and market the oil, natural gas and NGL (excluding costs of marketing services provided by Avalon);
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the Trust’s share of applicable taxes, including property taxes and taxes on the production
of oil, natural gas and NGL;
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the Trust’s liability for Texas franchise tax; and
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Trust administrative expenses, including fees paid to the Trustee and the Delaware Trustee, the
annual administrative services fee payable to Avalon, tax return and Schedule K-1 preparation and mailing costs, independent
auditor fees, registrar and transfer agent fees, and costs associated with compliance with federal securities laws and NYSE listing
requirements, including the preparation of annual and quarterly reports to Trust unitholders and current reports announcing the
amount of quarterly distributions by the Trust.
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In addition, the amount
of funds available for distribution to Trust unitholders is reduced by the amount of any cash reserves maintained by the Trustee
in respect of anticipated future Trust administrative expenses. Commencing with the distribution to unitholders paid in the first
quarter of 2019, the Trustee has withheld, and in the future intends to withhold, the greater of $190,000 or 3.5% of the funds
otherwise available for distribution each quarter to gradually increase cash reserves for the payment of future known, anticipated
or contingent expenses or liabilities by a total of approximately $2,275,000. In 2019, the Trustee withheld $760,000 from the funds
otherwise available for distribution to Trust unitholders. In February 2020, the Trustee withheld approximately $190,000 from
the funds otherwise available for distribution.
The amount of post-production
costs, taxes and expenses borne by the Trust may vary materially from quarter-to-quarter. The extent by which the costs are lower
in any quarter will directly decrease revenues received by the Trust from Avalon and such amount will be further decreased by expenses
of the Trust. As a result, distributions available to Trust unitholders may vary significantly quarter to quarter. Meanwhile, historical
post-production costs, taxes and expenses are not indicative of future post-production costs, taxes and expenses.
The Trust has
no hedges in place to protect against the price risk inherent in holding interests in oil and gas, commodities that are frequently
characterized by significant price volatility.
The Trust and SandRidge
were parties to a derivatives agreement that provided the Trust with the economic effect of certain derivative contracts between
SandRidge and a third party for production through March 31, 2015. From inception through the termination of the hedging arrangements,
the Trust received approximately $47.5 million that it would not have received without the hedging arrangements. The last of the
hedging arrangements expired on March 31, 2015. Consequently, Trust unitholders no longer have the benefit of any hedging
arrangements, and all production after March 31, 2015 is subject to the price risks inherent in holding interests in oil and
natural gas, both commodities that are frequently characterized by significant price volatility.
The Trust is
administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.
The business and affairs
of the Trust are administered by the Trustee. A Trust unitholder’s voting rights 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 outstanding Trust units, excluding Trust units held by Avalon (until such time as the total number
of Trust units held by Avalon is less than 10% of all issued and outstanding Trust units), voting in person or by proxy at a special
meeting of Trust unitholders at which a quorum is present called by either the Trustee or the holders of not less than 10% of the
outstanding Trust units. As a result, it may be difficult for Trust unitholders to remove or replace the Trustee without the cooperation
of holders of a substantial percentage of the outstanding Trust units.
Trust unitholders
have limited ability to enforce provisions of the Royalty Interests, and Avalon’s liability to the Trust is limited.
The Trust Agreement
permits the Trustee and the Trust to sue Avalon or any other future owner of the Underlying Properties to enforce the terms of
the Conveyances creating the Royalty Interests. If the Trustee does not take appropriate action to enforce provisions of the Conveyances,
a Trust unitholder’s 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 Avalon or any other party other
than the Trustee. As a result, Trust unitholders will not be able to sue Avalon or any future owner of the Underlying Properties
to enforce the Trust’s rights under the Conveyances. Furthermore, the Conveyances provide that, except as set forth in the
Conveyances, Avalon will not be liable to the Trust for the manner in which it performs its duties in operating the Underlying
Properties, the wells burdened by the Royalty Interests or the minerals in or under the Underlying Properties as long as it acts
in good faith and in accordance with the Reasonably Prudent Operator Standard. Furthermore, the Trust Agreement provides (a) that
Avalon (as successors to SandRidge) may exercise their rights and discharge their obligations fully, without hindrance or regard
to conflict of interest principles, duty of loyalty principles or other breach of fiduciary duties, all of which defense, claims
or assertions are expressly waived by the other parties to the Trust Agreement and the Trust unitholders, (b) neither Avalon
nor its affiliates shall be a fiduciary to the Trust or the Trust unitholders, and (c) to the extent that, at law or in equity,
Avalon has duties (including fiduciary duties) and liabilities to the Trust and Trust unitholders, such duties and liabilities
are eliminated to the fullest extent permitted by law.
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 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. However, courts in jurisdictions outside of
Delaware may not give effect to such limitation.
The sale of
Trust units by Avalon could have an adverse impact on the trading price of the Trust units.
As of March 10,
2020, Avalon owned 13,125,000 Trust units, all of which are pledged as collateral on Avalon’s secured revolving line of credit.
So long as the line of credit is outstanding, Avalon does not have the right to sell any or all of such Trust units without the
prior consent of its lender. In the event Avalon could obtain the permission of its lender to sell Trust units, any such sale could
have an adverse impact on the price of the Trust units depending on the number and manner in which the Trust units are sold by
Avalon.
Avalon could
have interests that conflict with the interests of the Trust and Trust unitholders.
As a working interest
owner in the Underlying Properties, Avalon could have interests that conflict with the interests of the Trust and the Trust unitholders.
For example:
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Avalon’s interests may conflict with those of the Trust and the Trust unitholders in situations
involving the maintenance, operation or abandonment of the Underlying Properties. Additionally, Avalon may, consistent with its
obligation to act in good faith and in accordance with the Reasonably Prudent Operator Standard, abandon a well that is uneconomic
or not generating revenues from production in excess of its operating costs, even though such well is still generating revenue
for the Trust unitholders. Avalon may make decisions with respect to expenditures and decisions to allocate resources on projects
that adversely affect the Underlying Properties, including reducing expenditures on these properties, which could cause oil, natural
gas and NGL production to decline at a faster rate and thereby result in lower cash distributions by the Trust in the future.
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Avalon may, without the consent or approval of the Trust unitholders, sell all or any part of its
retained interest in the Underlying Properties, if the Underlying Properties are sold subject to and burdened by the Royalty Interests.
Such sale may not be in the best interests of the Trust and Trust unitholders. For example, any purchaser may lack Avalon’s
experience in the Permian Basin or its creditworthiness.
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Avalon may, without the consent or approval of the Trust unitholders, require the Trust to release
Royalty Interests with an aggregate value of up to $5.0 million during any 12-month period in connection with a sale by Avalon
of a portion of its retained interest in the Underlying Properties. The value received by the Trust for such Royalty Interests
may not fully compensate the Trust for the value of future production attributable to the Royalty Interests burdening such Underlying
Properties.
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Avalon is permitted under the Conveyances creating the Royalty Interests to enter into new processing
and transportation contracts without obtaining bids from or otherwise negotiating with any independent third parties, and Avalon
will deduct from the Trust’s proceeds any charges under such contracts attributable to production from the Underlying Properties.
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Avalon can sell its Trust units regardless of the effects such sale may have on the market price
of Trust units or on the Trust itself. Additionally, Avalon can vote its Trust units in its sole discretion.
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In addition, Avalon has agreed that, if
at any time the Trust’s cash on hand (including available cash reserves) is not sufficient to pay the Trust’s ordinary
course administrative expenses as they become due, Avalon will, at the Trustee’s request, loan funds to the Trust necessary
to pay such expenses. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as
those which would be obtained in an arms’ length transaction between Avalon and an unaffiliated third party. If Avalon provides
such funds to the Trust, it would become a creditor of the Trust and its interests as a creditor could conflict with the interests
of unitholders since it is entitled to receive a return of the principal amount of such loan and interest earned thereon prior
to any further distributions to the Trust unitholders.
Avalon may sell
all or a portion of the Underlying Properties, subject to and burdened by the Royalty Interests; any such purchaser could have
a weaker financial position and/or be less experienced in oil and natural gas development and production than Avalon.
Trust unitholders
will not be entitled to vote on any sale of the Underlying Properties if the Underlying Properties are sold subject to and burdened
by the Royalty Interests, and the Trust will not receive any proceeds from any such sale. The purchaser would be responsible for
all of Avalon’s obligations relating to the Royalty Interests on the portion of the Underlying Properties sold, and Avalon
would have no continuing obligation to the Trust for those properties. Additionally, Avalon may enter into farmout or joint venture
arrangements with respect to the wells burdened by the Royalty Interests. Any purchaser, farmout counterparty or joint venture
partner could have a weaker financial position, or could be less experienced in oil and natural gas development and production
than Avalon, or both.
The value of
the Royalty Interests is highly dependent on the performance and financial condition of Avalon.
As of November 1,
2018, Avalon is the operator of all wells burdened by the Royalty Interests. The Conveyances provide that Avalon is obligated to
market, or cause to be marketed, the oil, natural gas and NGL produced by such wells (to the extent such wells are capable of producing
marketable hydrocarbons in paying quantities) from the Underlying Properties. If Avalon were to default on its obligation, the
cash distributions to the Trust unitholders may be materially reduced. The Trust is highly dependent on its Trustor, Avalon, for
multiple services, including the operation of the Trust wells, remittance of net proceeds from the sale of associated production
to the Trust, administrative services such as accounting, tax preparation, bookkeeping and informational services performed on
behalf of the Trust. Due to the Trust’s reliance on Avalon to fulfill these obligations, the value of the Royalty Interests
and its ultimate cash available for distribution is highly dependent on Avalon’s performance. If the reduced demand for crude
oil in the global market resulting from the economic effects of the coronavirus pandemic and the recent reduction in the benchmark
price of crude oil persist for the near term or longer, such factor are likely to have a negative impact on Avalon’s financial
condition. This negative impact could affect Avalon’s ability to operate the wells and provide services to the Trust.
The bankruptcy
of operators could impede the operation of wells.
The value of the Royalty
Interests and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of the
operator of the wells. Avalon has not agreed with the Trust to maintain a certain net worth or to be restricted by other similar
covenants.
The ability to operate
the Underlying Properties depends on an operators’ future financial condition, economic performance and access to capital,
which in turn will depend upon the supply and demand for oil, natural gas and NGL, prevailing economic conditions and financial,
business and other factors, many of which are beyond the control of such operators.
In the event of any
future bankruptcy of Avalon or any other future operator of the Underlying Properties, the value of the Royalty Interests could
be adversely affected by, among other things, delay or cessation of payments under the Royalty Interests, business disruptions
or cessation of operations by the operator, replacements of operators, inability to find a replacement operator where necessary,
reduced production of petroleum reserves. Any of such events would likely result in decreased distributions to Trust unitholders.
Oil and natural
gas wells are subject to operational hazards that can cause substantial losses. Avalon maintains insurance but may not be adequately
insured for all such hazards.
There are a variety
of operating risks inherent in oil, natural gas and NGL production and associated activities, such as fires, leaks, explosions,
mechanical problems, major equipment failures, uncontrollable flow of oil, natural gas, NGL, water or drilling fluids, casing collapses,
abnormally pressurized formations and natural disasters. The occurrence of any of these or similar accidents that temporarily or
permanently halt the production and sale of oil, natural gas and NGL at any of the Underlying Properties will reduce Trust distributions
by reducing the amount of proceeds available for distribution.
Additionally, if any
of such risks or similar accidents occur, Avalon could incur substantial losses as a result of injury or loss of life, severe damage
or destruction of property, natural resources and equipment, regulatory investigation and penalties and environmental damage and
clean-up responsibilities. If Avalon were to experience any of these problems, its ability to conduct operations and perform its
obligations to the Trust could be adversely affected. Although Avalon maintains insurance coverage it deems appropriate for these
risks with respect to the Underlying Properties, Avalon’s operations may result in liabilities exceeding such insurance coverage
or liabilities not covered by insurance. If a well is damaged, Avalon would have no obligation to drill a replacement well or make
the Trust whole for the loss. The Trust does not maintain any type of insurance against any of the risks of conducting oil and
gas exploration and production and related activities.
The operation
of the Underlying Properties is subject to complex federal, state, local and other laws and regulations that could adversely affect
the cost, manner and feasibility of conducting operations on the properties, which in turn could negatively impact Trust distributions.
Oil, natural gas and
NGL production, transportation and treatment operations are subject to complex and stringent laws and regulations. In order to
conduct operations in compliance with these laws and regulations, numerous permits, approvals and certificates are required from
various federal, state and local governmental authorities. Compliance with these existing laws and regulations may require the
incurrence of substantial costs by Avalon or other future operators of the Underlying Properties. Additionally, there has been
a variety of regulatory initiatives at the federal and state levels to further regulate oil and natural gas operations in certain
locations. Any increased regulation or suspension of oil and natural gas operations, or revision or reinterpretation of existing
laws and regulation, could result in delays and higher operating costs. Such costs or significant delays could have a material
adverse effect on the operation of the Underlying Properties, which in turn could negatively impact Trust distributions.
Laws and regulations
governing oil and natural gas exploration and production may also affect production levels. Avalon is required to comply with federal
and state laws and regulations governing conservation matters, including: (i) provisions related to the unitization or pooling
of the oil and natural gas properties; (ii) the establishment of maximum rates of production from wells; (iii) the spacing
of wells; and (iv) the plugging and abandonment of wells. These and other laws and regulations can limit the amount of oil,
natural gas and NGL Avalon can produce from the wells which it owns and operates, including those wells burdened by the Royalty
Interests, which in turn could negatively impact Trust distributions.
New laws or regulations,
or changes to existing laws or regulations may unfavorably impact Avalon, could result in increased operating costs and could have
a material adverse effect on Avalon’s financial condition and results of operations. Additionally, federal and state regulatory
authorities may expand or alter applicable pipeline safety laws and regulations, compliance with which may require increased capital
expenditures by Avalon and third-party downstream oil, natural gas and NGL transporters. These and other potential regulations
could increase Avalon’s operating costs, reduce Avalon’s liquidity, delay Avalon’s operations, increase direct
and third-party post production costs associated with the Trust’s interests or otherwise alter the way Avalon conducts its
business, which could have a material adverse effect on Avalon’s financial condition, results of operations and cash flows
and which could reduce cash received by or available for distribution, including any amounts paid by Avalon for transportation
on downstream interstate pipelines.
Please see the section
titled “Regulation” under Item 1. Business above for a more complete discussion of applicable federal and state laws
impacting the Underlying Properties and their operation.
Should Avalon
fail to comply with all applicable statutes, rules, regulations and orders of FERC or the FTC, Avalon could be subject to substantial
penalties and fines.
Under the Energy Policy
Act of 2005 and implementing regulations, FERC prohibits market manipulation in connection with the purchase or sale of natural
gas. The FTC also prohibits manipulative or fraudulent conduct in the wholesale petroleum market with respect to sales of commodities,
including crude oil, condensate and natural gas liquids. These agencies have substantial enforcement authority, including the ability
to impose penalties for current violations in excess of $1 million per day for each violation. FERC has also imposed requirements
related to reporting of natural gas sales volumes that may impact the formation of prices indices. Additional rules and legislation
pertaining to these and other matters may be considered or adopted from time to time. Failure to comply with these or other laws
and regulations administered by these agencies could subject Avalon to criminal and civil penalties, as described in Item 1 under
“Regulation—Oil and Natural Gas Regulations” above.
The operation
of the Underlying Properties is subject to environmental and occupational safety and health laws and regulations that could adversely
affect the cost, manner or feasibility of conducting operations or result in significant costs and liabilities.
The oil, natural gas
and NGL production operations on the Underlying Properties are subject to stringent and complex federal, state, regional and local
laws and regulations governing worker safety and health, the discharge and disposal of materials into the environment or otherwise
relating to environmental protection. Failure to comply with these laws and regulations may result in litigation; the assessment
of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action
obligations; the occurrence of delays or restrictions in permitting or performance of projects; and the issuance of orders and
injunctions limiting or preventing some or all operations relating to the Underlying Properties in affected areas.
Under certain environmental
laws and regulations, an owner or operator of the Underlying Properties could be subject to joint and several liability for the
investigation, removal or remediation of previously released materials or property contamination, regardless of whether the owner
or operator was responsible for such release or contamination or whether the operations were in compliance with all applicable
laws at the time the release or contamination occurred. Private parties, including the owners of properties upon which wells are
drilled or facilities where petroleum hydrocarbons or wastes are taken for reclamation or disposal may also have the right to pursue
legal actions to enforce compliance, to seek damages for contamination, or for personal injury or property damage.
Changes in environmental
laws and regulations occur frequently, and any changes that result in delays or restrictions in permitting or development of projects
or more stringent or costly construction, drilling, water management, or completion activities or waste handling, storage, transport,
remediation or disposal, emission or discharge requirements could require significant expenditures by Avalon to attain and maintain
compliance and may otherwise have a material adverse effect on the results of operations, competitive position or financial condition
of Avalon. In addition, delays or restrictions in permitting or development of projects that reduce or temporarily or permanently
halt the production of oil, natural gas and natural gas liquids at any of the Underlying Properties will reduce Trust distributions
by reducing the amount of proceeds available for distribution.
Climate change
laws and regulations restricting emissions of GHGs could result in increased operating costs with respect to the Underlying Properties.
In 2009, the EPA published
its findings that emissions of carbon dioxide, methane and certain other “greenhouse gases” (collectively, “GHGs”)
present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing
to warming of the earth’s atmosphere and other climatic changes. The EPA has taken a number of steps aimed at gathering information
about, and reducing the emissions of, GHGs from industrial sources, including oil and natural gas sources. The EPA has adopted
rules requiring the reporting of GHG emissions from oil, natural gas and NGL production and processing facilities on an annual
basis, as well as reporting GHG emissions from gathering and boosting systems, oil well completions and workovers using hydraulic
fracturing, as well as rules. adopting New Source Performance Standards (“NSPS”) for new, modified, or reconstructed
oil and gas facilities that require control of the GHG methane from affected facilities, including requirements to find and repair
fugitive leaks of methane emissions at well sites (“Methane Rule”). Following the 2016 presidential election
and change in administrations, in 2017 the EPA proposed to delay implementation of the Methane Rule, and also convened a reconsideration
proceeding that resulted in two 2018 rulemaking projects aimed at rolling back certain Methane Rule requirements. In 2019,
the EPA proposed to 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, non-methane pollutants. These actions, like the
Methane Rule itself, have been (or are likely to be) challenged in courts. The ultimate fate of the Methane Rule requirements
is unclear. Nevertheless, regulations promulgated under the CAA may require Avalon to incur development expenses to install and
utilize specific equipment, technologies, or work practices to control emissions from its operations.
A number of state
and regional efforts also are aimed at tracking and/or reducing GHG emissions by means of cap-and-trade programs that typically
require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. On an international
level, the United States is one of almost 200 nations that in December 2015 entered into the Paris Agreement, which calls
for countries to set their own GHG emissions targets and maintain transparency regarding the measures each country will use to
achieve its GHG emissions targets. However, the Paris Agreement does not impose any binding obligations on the United States. Moreover,
in June 2017, President Trump announced that the United States would withdraw from the Paris Agreement but may enter into
a future international agreement related to GHGs. In August 2017, the U.S. State Department officially informed the United
Nations of the intent of the United States to withdraw from the Paris Agreement and such withdrawal has been finalized. Further,
several states and local governments remain committed to the principles of the Paris Agreement in their effectuation of policy
and regulations. It is not possible at this time to predict how or when the United States might impose restrictions on GHGs as
a result of the Paris Agreement.
For a more detailed
discussion of applicable federal and state laws regarding air emission and climate change regulation, please see the section titled
“Regulation – Air Emissions and Climate Change” under Item 1. Business above.
The adoption and implementation
of any laws or regulations imposing reporting obligations on, or limiting emissions of GHGs from, the equipment and operations
of Avalon or other operators of the Underlying Properties could require additional expenditures to monitor, report and potentially
reduce emissions of GHGs associated with their operations or could adversely affect demand for the oil, natural gas and NGL produced
from the Underlying Properties. Recently, activists concerned about the potential effects of climate change have directed their
attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and
other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could
make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to
climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until
after 2040, and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally,
to the extent increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that could have significant
physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events, such events could
have a material adverse effect on the Underlying Properties, and potentially subject the Underlying Properties and the operations
of Avalon or other operators of the Underlying Properties to greater regulation. The occurrence of any of these events that reduce
or temporarily or permanently halt the production of oil, natural gas and natural gas liquids at any of the Underlying Properties
will reduce Trust distributions by reducing the amount of proceeds available for distribution.
The Trust is
subject to the requirements of the Sarbanes-Oxley Act of 2002, which may impose cost and operating challenges on it.
The Trust is subject
to certain of the requirements of the Sarbanes-Oxley Act of 2002 which requires, among other things, maintenance by the Trust of,
and reports regarding the effectiveness of, a system of internal control over financial reporting. Complying with these requirements
may pose operational challenges and may cause the Trust to incur unanticipated expenses. Any failure by the Trust to comply with
these requirements could lead to a loss of public confidence in the Trust’s internal controls and in the accuracy of the
Trust’s publicly reported results.
Cyber-attacks
or other failures in telecommunications or IT systems could result in information theft, data corruption and significant disruption
of Avalon’s business operations.
Avalon relies on information
technology (“IT”) systems and networks in connection with its business activities, including certain of its
development and production activities. Avalon 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, natural gas and NGL 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 in the oil and gas industry, 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 Avalon’s systems and networks, the confidentiality, availability and integrity of
its data and the physical security of its employees and assets. Avalon has not experienced any attempts by hackers and other third
parties to gain unauthorized access to its IT systems and networks. However, if any such attempt were to occur, there is no assurance
that Avalon would be successful in preventing a cyber-attack or adequately mitigating the effect of such cyber-attack. Any cyber-attack
could have a material adverse effect on Avalon’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 Avalon to implement further data protection measures.
In addition to the
risks presented to Avalon’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 Avalon’s ability to control but could have a material adverse effect on Avalon’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.
Legislation
or regulatory initiatives intended to address seismic activity are restricting and could further restrict Avalon’s ability
and the ability of other operators of the Underlying Properties to dispose of waste water produced alongside hydrocarbons.
Large volumes of waste
water produced alongside Avalon’s and other operators’ oil, natural gas and NGL on the Underlying Properties in connection
with drilling and production operations are disposed of pursuant to permits issued by governmental authorities overseeing such
disposal activities. While these permits are issued pursuant to existing laws and regulations, these legal requirements are subject
to change, which could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements,
owing to, among other things, concerns of the public or governmental authorities regarding such gathering or disposal activities.
Furthermore, in response
to recent seismic events near underground disposal wells used for the disposal by injection of produced water resulting from oil
and natural gas activities, federal and some state agencies are investigating whether such wells have caused increased seismic
activity, and some states have restricted, suspended or shut down the use of such disposal wells. For example, in October 2014,
the Texas Railroad Commission, or TRC, published a new rule governing permitting or re-permitting of disposal wells that would
require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal
well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee
or an applicant of a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal
zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity,
then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. Evaluation
of seismic incidents and whether or to what extent those events are induced by the injection of saltwater into disposal wells continues
to evolve, as governmental authorities consider new and/or past seismic incidents in areas where salt water disposal activities
occur or are proposed to be performed. The adoption of any new laws, regulations, or directives that restrict Avalon’s ability
to dispose of saltwater generated by production and development activities on the Underlying Properties, whether by plugging back
the depths of disposal wells, reducing the volume of salt water disposed in such wells, restricting disposal well locations or
otherwise, or by requiring Avalon to shut down disposal wells, which could negatively affect the economic lives of the Underlying
Properties and have a material adverse effect on the Trust.
Tax Risks Related to the Trust Units
The Trust’s
tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the U.S. Internal Revenue Service
(“IRS”) were to treat the Trust as a corporation for U.S. federal income tax purposes, then its cash available for
distribution to its unitholders would be substantially reduced.
The anticipated after-tax
economic benefit of an investment in the Trust units depends largely on the Trust being treated as a partnership for U.S. federal
income tax purposes. The Trust has not requested, and does not plan to request, a ruling from the IRS, on this or any other tax
matter affecting it. It is possible in certain circumstances for a publicly traded trust otherwise treated as a partnership, such
as the Trust, to be treated as a corporation for U.S. federal income tax purposes. In addition, a change in current law could cause
the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to federal taxation as an
entity.
If the Trust were
treated as a corporation for U.S. federal income tax purposes, it would pay federal income tax on its taxable income at the corporate
tax rate, which after December 31, 2017 is a maximum of 21%, and likely would be required to also pay state income tax on
its taxable income at the corporate tax rate of such state. Distributions to Trust unitholders generally would be taxed again as
corporate distributions, and no income, gains, losses, deductions or credits would flow through to unitholders. Because additional
tax would be imposed upon the Trust as a corporation, its cash available for distribution to unitholders would be substantially
reduced. Therefore, treatment of the Trust as a corporation would result in a material reduction in the anticipated cash flow and
after-tax return to the Trust unitholders, likely causing a substantial reduction in the value of the Trust units.
If the Trust
were subjected to a material amount of additional entity-level taxation by individual states, it would reduce the Trust’s
cash available for distribution to unitholders.
The Trust is required
to pay Texas franchise tax each year at a maximum effective rate (subject to changes in the statutory rate) of 0.525% of its gross
income. This rate of tax is subject to change by new legislation at any time. Changes in current Texas state law may subject the
Trust to additional entity-level taxation. Because of widespread state budget deficits and other reasons, Texas is evaluating ways
to subject partnerships to entity-level taxation through the imposition of state franchise and other forms of taxation. Additional
imposition of such taxes may substantially reduce the cash available for distribution to unitholders and, therefore, negatively
impact the value of an investment in Trust units.
Upon examination,
the state of Texas may contest any of the tax positions the Trust has taken. Audit adjustments to an entity-level state tax,
such as Texas franchise tax (including any applicable penalties and interest), are collected directly from the Trust upon completion
of the examination.
Tax legislation
enacted in 2017 may have a significant impact on the taxation of the Trust and Trust unitholders.
The Tax Cuts and Jobs
Act (“TCJA”) enacted in December 2017 provides the most substantial tax reform in over thirty years. In
general, the TCJA lowers tax rates, eliminates or limits numerous deductions and other tax benefits, and significantly changes
international tax rules. Given the complexity of the TCJA and the significant changes to prior tax law, and the significant amount
of regulations that the Treasury Department and the IRS have yet to issue, propose and finalize to interpret and implement TCJA
changes, the impact and effect of the legislation on the Trust and Trust unitholders in respect of income and loss of the Trust
remains uncertain.
The foregoing is not
a complete summary of all of the changes in law that may apply to or impact the Trust or a unitholder with respect to income of
the Trust (or otherwise), unitholders strongly are urged to consult with their own tax advisors to determine how they might be
affected by the TCJA, both generally and specifically with respect to their ownership of trust units.
The tax treatment
of an investment in Trust units could be affected by potential legislative changes, possibly on a retroactive basis.
Current law may change
so as to cause the Trust to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Trust to
entity-level taxation. Specifically, the present U.S. federal income tax treatment of publicly-traded partnerships, including the
Trust, or an investment in the Trust units may be modified by administrative, legislative or judicial interpretation at any time.
For example, from time to time, members of the U.S. Congress propose and consider substantive changes to existing federal income
tax laws that could affect publicly traded partnerships. Such proposals, if adopted, could eliminate the qualifying income exception
for publicly traded partnerships deriving qualifying income from activities relating to fossil fuels thus treating such partnerships
as corporations. We currently rely upon this qualifying income exemption for our treatment of the Trust as a partnership for U.S.
federal income tax purposes.”
Any modification to
the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the
exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We
are unable to predict whether any of these changes or other proposals ultimately will be enacted. Any such changes could
have a material adverse effect on the value of the Trust units.
The Trust has
adopted and may continue to adopt positions that may not conform to all aspects of existing Treasury Regulations. If the IRS contests
the tax positions the Trust takes, the value of the Trust units may be adversely affected, the cost of any IRS contest will reduce
the Trust’s cash available for distribution and income, gains, losses and deductions may be reallocated among Trust unitholders.
The TCJA alters the procedures for assessing and collecting income taxes due for taxable years beginning after December 31,
2017, in a manner that could substantially reduce cash available for distribution to Trust unitholders.
If the IRS contests
any of the U.S. federal income tax positions the Trust takes or has taken, the value of the Trust units may be adversely affected,
because the cost of any IRS contest will reduce the Trust’s cash available for distribution and income, gain, loss and deduction
may be reallocated among Trust unitholders. For example, the Trust generally prorates its items of income, gain, loss and deduction
between transferors and transferees of the Trust units each quarter based upon the record ownership of the Trust units on the quarterly
record date in such quarter, instead of on the basis of the date a particular Trust unit is transferred. Although simplifying conventions
are contemplated by the Internal Revenue Code, and most publicly-traded partnerships use similar simplifying conventions, the use
of these methods may not be permitted under existing Treasury Regulations, and, accordingly, Avalon’s counsel is unable to
opine as to the validity of this method. If the IRS were to challenge the Trust’s proration method, the Trust may be required
to change its allocation of items of income, gain, loss and deduction among the Trust unitholders and the costs to the Trust of
implementing and reporting under any such changed method may be significant.
The Trust has not
requested a ruling from the IRS with respect to its treatment as a partnership for U.S. federal income tax purposes or any other
tax matter affecting the Trust. The IRS may adopt positions that differ from the conclusions of Avalon’s counsel or from
the positions the Trust takes. It may be necessary to resort to administrative or court proceedings to attempt to sustain some
or all of the conclusions of Avalon’s counsel or the positions the Trust takes. A court may not agree with some or all of
the conclusions of Avalon’s counsel or positions the Trust takes. Any contest with the IRS may materially and adversely impact
the market for the Trust units and the price at which they trade. In addition, the Trust’s costs of any contest with the
IRS will be borne indirectly by the Trust unitholders, because the costs will reduce the Trust’s cash available for distribution.
The TCJA enacted in
2017 and applicable to the Trust for taxable years beginning after December 31, 2017, alters the procedures for auditing large
partnerships and also alters the procedures for assessing and collecting income taxes due (including applicable penalties and interest)
as a result of an audit. Unless the Trust is eligible to (and chooses to) elect to issue revised Schedules K-1 to Trust unitholders
with respect to an audited and adjusted return, the IRS may assess and collect income taxes (including any applicable penalties
and interest) directly from the Trust in the year in which the audit is completed under the new rules, which effectively would
impose an entity level tax on the Trust. If the Trust is required to pay income taxes, penalties and interest as the result of
audit adjustments, cash available for distribution to Trust unitholders may be substantially reduced. In addition, because payment
would be due for the taxable year in which the audit is completed, Trust unitholders during that taxable year would bear the expense
of the adjustment even if they were not Trust unitholders during the audited taxable year.
Each Trust unitholder
is required to pay taxes on the unitholder’s share of the Trust’s income even if the unitholder does not receive cash
distributions from the Trust equal to the unitholder’s share of the Trust’s taxable income.
Because the Trust
unitholders are treated as partners to whom the Trust allocates taxable income that could be different in amount than the cash
the Trust distributes, each unitholder may be required to pay any federal income taxes and, in some cases, state and local income
taxes on the unitholder’s share of the Trust’s taxable income even if the unitholder does not receive cash distributions
from the Trust equal to the unitholder’s share of the Trust’s taxable income or even equal to the actual tax liability
that results from that income.
Tax gain or
loss on the disposition of the Trust units could be more or less than expected.
If a Trust unitholder
sells its Trust units, such unitholder will recognize a gain or loss equal to the difference between the amount realized and the
unitholder’s tax basis in those Trust units. Because distributions in excess of a unitholder’s allocable share of the
Trust’s net taxable income decrease the unitholder’s adjusted tax basis in its Trust units, the amount, if any, of
such prior excess distributions with respect to the Trust units sold by a unitholder will, in effect, become taxable income to
such unitholder if the unitholder sells such Trust units at a price greater than the unitholder’s tax basis in those Trust
units, even if the price the unitholder receives is less than the unitholder’s original cost. Furthermore, a substantial
portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items,
including depletion recapture.
The ownership
and disposition of Trust units by tax-exempt organizations and non-U.S. persons may result in adverse tax consequences to them.
Tax-Exempt Organizations. Employee
benefit plans and most other organizations exempt from U.S. federal income tax including individual retirement accounts (known
as IRAs) and other retirement plans are subject to U.S. federal income tax on “unrelated business taxable income”.
Because all of the income of the Trust is royalty income, interest income, and gain from the sale of real property, none of which
is expected to be unrelated business taxable income, any such organization exempt from U.S. federal income tax is not expected
to be taxed on income generated by ownership of Trust units so long as neither the property held by the Trust nor the Trust units
are debt-financed property within the meaning of Section 514(b) of the Internal Revenue Code (“IRC”).
However, such investors should consult their own tax advisors as to the treatment of income from the Trust.
Non-U.S. Persons. Pursuant
to Section 1446 of the IRC, withholding tax on income effectively connected to a United States trade or business allocated
to non-U.S. persons (“ECI”) should be made at the highest marginal rate. Under Section 1441 of the IRC,
withholding tax on fixed, determinable, annual, periodic income from United States sources allocated to non-U.S. persons should
be made at 30% of gross income unless the rate is reduced by treaty. Nominees and brokers should withhold at the highest marginal
rate on the distribution made to non-U.S. persons. The TCJA, discussed above, treats a non-U.S. holder’s gain on the sale
of Trust units as ECI to the extent such holder would have had ECI if the Trust had sold all of its assets at fair market value
on the date of the sale of such Trust units. The TCJA also requires the transferee of Trust units to withhold 10% of the amount
realized on the sale or exchange of such units (generally, the purchase price) unless the transferor certifies that it is not a
non-resident alien individual or foreign corporation. Pending the finalization of proposed regulations under Section 1446
of the IRC, the IRS has suspended this new withholding obligation with respect to publicly traded partnerships such as the Trust,
which is classified as a partnership for federal and state income tax purposes.
The Trust treats
each purchaser of Trust units as having the same economic attributes without regard to the actual Trust units purchased. The IRS
may challenge this treatment, which could adversely affect the value of the Trust units.
Due to a number of
factors, including the Trust’s inability to match transferors and transferees of Trust units, the Trust may adopt positions
that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely
alter the tax effects of an investment in Trust units. It also could affect the timing of tax benefits or the amount of gain from
a unitholder’s sale of Trust units and could have a negative impact on the value of the Trust units or result in audit adjustments
to a unitholder’s tax returns.
The Trust prorates
its items of income, gain, loss and deduction between transferors and transferees of the Trust units each quarter based upon the
record ownership of the Trust units on the quarterly record date, in such quarter, 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
prorates its items of income, gain, loss and deduction between transferors and transferees of the Trust units based upon the record
ownership of the Trust units on the quarterly record date in such quarter instead of on the basis of the date a particular Trust
unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly,
the Trust’s counsel is unable to opine as to the validity of this method. If the IRS were to challenge the Trust’s
proration method, the Trust may be required to change its allocation of items of income, gain, loss and deduction among the Trust
unitholders and the costs to the Trust of implementing and reporting under any such changed method may be significant.
A Trust unitholder
whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed
of those Trust units. If so, such unitholder would no longer be treated for tax purposes as a partner (for tax purposes) with respect
to those Trust units during the period of the loan and may recognize gain or loss from the disposition.
Because a Trust unitholder
whose Trust units are loaned to a “short seller” to cover a short sale of Trust units may be considered as having disposed
of the loaned Trust units, he or she may no longer be treated for tax purposes as a partner with respect to those Trust units during
the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during
the period of the loan to the short seller, any of the Trust’s income, gains, losses or deductions with respect to those
Trust units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those Trust units
could be fully taxable as ordinary income. Trust unitholders desiring to assure their status as partners (for tax purposes) and
avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements
to prohibit their brokers from loaning their Trust units.
The Trust may
adopt certain valuation methodologies that may affect the income, gain, loss and deduction allocable to the Trust unitholders.
The IRS may challenge this treatment, which could adversely affect the value of the Trust units.
The U.S. federal income
tax consequences of the ownership and disposition of Trust units will depend in part on the Trust’s estimates of the relative
fair market values, and the initial tax basis of the Trust’s assets. Although the Trust may from time to time consult with
professional appraisers regarding valuation matters, the Trust will make many of the relative fair market value estimates itself.
These estimates and determinations of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates
of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions
previously reported by Trust unitholders might change, and Trust unitholders might be required to adjust their tax liability for
prior years and incur interest and penalties with respect to those adjustments.
The availability
and extent of percentage depletion deductions to the Trust unitholders for any taxable year is uncertain.
The payments received
by the Trust with respect to the perpetual portion of the Royalty Interests are treated as mineral royalty interests for U.S. federal
income tax purposes and taxable as ordinary income. Trust unitholders are entitled to deductions for the greater of either cost
depletion or (if otherwise allowable) percentage depletion with respect to such income. Although the Internal Revenue Code requires
each Trust unitholder to compute his own depletion allowance and maintain records of his share of the adjusted tax basis of the
underlying royalty interest for depletion and other purposes, the Trust will furnish each of the Trust unitholders with information
relating to this computation for U.S. federal income tax purposes. Each Trust unitholder, however, remains responsible for calculating
his own depletion allowance and maintaining records of his share of the adjusted tax basis of the perpetual royalties for depletion
and other purposes. The rules with respect to this depletion allowance are complex and must be computed separately by each
Trust unitholder and not by the Trust for each oil or natural gas property. As a result, the availability or extent of percentage
depletion deductions to the Trust unitholders for any taxable year is uncertain.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding the Trust’s
properties is included in Item 1 of this report. Also, refer to Note 9 to the financial statements included in Item 8 of this report.
Item 3. Legal Proceedings
None.
Item 4. Mine Safety Disclosures
Not applicable.
NOTES TO FINANCIAL STATEMENTS
1. Organization of the Trust
Nature of Business. SandRidge
Permian Trust (the “Trust”) is a statutory trust formed under the Delaware Statutory Trust Act pursuant to a trust
agreement, as amended and restated, by and among SandRidge Energy, Inc. (“SandRidge”), as Trustor, The Bank of
New York Mellon Trust Company, N.A., as Trustee (the “Trustee”), and The Corporation Trust Company, as Delaware Trustee
(the “Delaware Trustee”) (such amended and restated trust agreement, as amended to date, the “trust agreement”).
The Trust holds royalty
interests conveyed by SandRidge from its interests in specified oil and natural gas properties located in Andrews County, Texas
(the “Underlying Properties”). These royalty interests were conveyed by SandRidge to the Trust (the “Royalty
Interests”) concurrent with the initial public offering of the Trust’s common units (“Trust units”) in
August 2011. As consideration for conveyance of the Royalty Interests, the Trust remitted the proceeds of the offering, along
with 4,875,000 Trust units and 13,125,000 subordinated units of the Trust (“subordinated units”), to certain wholly
owned subsidiaries of SandRidge. At December 31, 2019, SandRidge owned 13,125,000 Trust units, or 25% of all Trust units.
Pursuant to a development
agreement between the Trust and SandRidge, SandRidge was obligated to drill, or cause to be drilled, 888 development wells within
an area of mutual interest (“AMI”) by March 31, 2016 (the “Trust Development Wells”). SandRidge fulfilled
this obligation in November 2014, and, as a result, the subordinated units converted to Trust units in January 2016.
On November 1,
2018, SandRidge sold all of its interests in the Underlying Properties and all of its outstanding Trust units (the “Sale
Transaction”) to Avalon Energy, LLC, a Texas limited liability company (“Avalon”). The Conveyances permitted
SandRidge to sell all or any part of its interest in the Underlying Properties, where the Underlying Properties were sold subject
to and burdened by the Royalty Interests. In connection with the transaction (the “Sale Transaction”), Avalon and its
affiliates assumed all of SandRidge’s obligations under the conveyances and the trust agreement and the administrative services
agreement between SandRidge and the Trust pursuant to which SandRidge and Avalon have provided accounting, tax preparation, bookkeeping
and informational services to the Trust. In addition, SandRidge assigned its rights to Avalon under the registration rights agreement
between SandRidge and the Trust. As of December 31, 2019, Avalon holds 13,125,000 Trust units, or 25% of all Trust units.
The Trust is passive
in nature and neither the Trust nor the Trustee has any control over, or responsibility for, any operating or capital costs related
to the Underlying Properties. The business and affairs of the Trust are administered by the Trustee. The trust agreement generally
limits the Trust’s business activities to owning the Royalty Interests and certain activities reasonably related thereto,
including activities required or permitted by the terms of the conveyances related to the Royalty Interests.
Distributions.
The Trust makes quarterly cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s
administrative expenses, property tax and Texas franchise tax and cash reserves withheld by the Trustee, on or about the 60th day
following the completion of each quarter. Due to the timing of the payment of production proceeds to the Trust, each distribution
covers production from a three-month period consisting of the first two months of the most recently ended quarter and the final
month of the quarter preceding it.
Dissolution. The
Trust will dissolve and begin to liquidate on March 31, 2031 (the “Termination Date”), unless sooner dissolved
in accordance with the terms of the trust agreement as described below, and will soon thereafter wind up its affairs and terminate.
At the Termination Date, 50% of the Royalty Interests will revert automatically to Avalon. The remaining 50% of the Royalty Interests
will be sold at that time, with the net proceeds of the sale, as well as any remaining Trust cash reserves, distributed to the
unitholders on a pro rata basis, subject to Avalon’s right of first refusal to purchase the Royalty Interests retained by
the Trust at the Termination Date. The Trust may also dissolve should one of the following events occur prior to the Termination
Date: (a) the Trust sells all of the Royalty Interests; (b) cash available for distribution for any four consecutive
quarters, on a cumulative basis, is less than $5.0 million; (c) the Trust unitholders approve an earlier dissolution of the
Trust; or (d) the Trust is judicially dissolved pursuant to the provisions of the Delaware Statutory Trust Act. In the case
of any of the foregoing, the Trustee would then sell all of the Trust’s assets (subject to Avalon’s right of first
refusal to purchase the Royalty Interests retained by the Trust as of the date of such event), either by private sale or public
auction, and distribute the net proceeds of the sale to the Trust unitholders after payment, or reasonable provision for payment,
of all Trust liabilities.
2. Significant Accounting Policies
Basis of Accounting. The
financial statements of the Trust differ from financial statements prepared in accordance with accounting principles generally
accepted in the United States of America (“GAAP”) as the Trust records revenues when cash is received (rather than
when earned) and expenses when paid (rather than when incurred) and may also establish cash reserves for contingencies, which would
not be accrued in financial statements prepared in accordance with GAAP. This comprehensive basis of accounting other than GAAP
corresponds to the accounting permitted for royalty trusts by the United States Securities and Exchange Commission (“SEC”)
as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Amortization of investment
in the Royalty Interests, calculated on a unit-of-production basis, and any impairments are charged directly to trust corpus. Distributions
to unitholders are recorded when declared.
Significant Accounting
Policies. Most accounting pronouncements apply to entities whose financial statements are prepared in accordance with
GAAP, which may require such entities to accrue or defer revenues and expenses in a period other than when such revenues are received
or expenses are paid. Because the Trust’s financial statements are prepared on the modified cash basis as described above,
most accounting pronouncements are not applicable to the Trust’s financial statements.
Use of Estimates. The
preparation of financial statements requires the Trust to make estimates and assumptions that affect the reported amounts of assets
and trust corpus and the reported amounts of revenues and expenses during the reporting period. Significant estimates that impact
the Trust’s financial statements include estimates of proved oil, natural gas and natural gas liquids (“NGL”)
reserves, which are used to compute the Trust’s amortization of investment in the Royalty Interests and, as necessary, to
evaluate potential impairment of its investment in the Royalty Interests. Actual results could differ from those estimates.
Distributable Income
Per Unit. Distributable income per unit amounts as calculated for the periods presented in the accompanying statements of distributable
income may differ from declared distribution amounts per unit due to rounding and interest income. All Trust unitholders share
on a pro rata basis in the Trust’s distributable income (See Note 1).
Cash and Cash Equivalents. Cash
and cash equivalents consist of all highly-liquid instruments with original maturities of three months or less.
Investment in
Royalty Interests. Significant dispositions or abandonments of the Underlying Properties are charged to investment
in the Royalty Interests and the trust corpus. Amortization of investment in the Royalty Interests is calculated on a
calendar-based units-of-production basis, whereby the Trust’s cost basis is divided by the proved reserves attributable
to the Royalty Interests to derive an amortization rate per reserve unit. Amortization is recorded when units are produced.
Such amortization does not reduce distributable income, rather it is charged directly to trust corpus. Revisions to estimated
future units-of-production are treated on a prospective basis beginning on the date significant revisions are known.
Impairment of Investment
in Royalty Interests. On a quarterly basis, the Trust
evaluates the carrying value of the Investment in Royalty Interests by comparing the undiscounted cash flows expected to be realized
from the Royalty Interest to the carrying value. If the expected future undiscounted cash flows are less than the carrying value,
the Trust recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the Royalty
Interest, which is determined using future cash flows of the net oil, natural gas and NGL reserves attributable to the Royalty
Interests, discounted at a rate based upon the weighted average cost of capital of publicly traded royalty trusts. The weighted
average cost of capital is based upon inputs that are readily available in the public market. The future cash flows of the net
oil, natural gas and NGL reserves attributable to the Royalty Interests utilizes the oil and natural gas futures prices readily
available in the public market adjusted for differentials and estimated quantities of oil, natural gas and NGL reserves that geological
and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing
economic and operating conditions. As there are numerous uncertainties inherent in estimating quantities of proved reserves, these
quantities are a significant unobservable input resulting in the fair value measurement being considered a level 3 measurement
within the fair value hierarchy. There were no impairments in the carrying value of the Investment in Royalty Interests during
2019 or 2018. Material write-downs in subsequent periods may occur if commodity prices decline. Any impairment would result in
a non-cash charge to trust corpus and would not affect the Trust's distributable income. See “Risks and Uncertainties”
in Note 5 below for further discussion.
Revenue and Expenses. Revenues
received by the Trust are reduced by post-production expenses, production taxes and general and administrative expenses paid and
are adjusted for cash reserves withheld by the Trustee in order to determine distributable income. The Royalty Interests are not
burdened by field and lease operating expenses.
Concentration of
Risk. The Trust maintains cash balances at one financial institution which are insured by the Federal Deposit Insurance
Corporation up to $250,000. The Trust typically has balances in these accounts that substantially exceed the federally insured
limit. The Trust does not anticipate any loss associated with balances exceeding the federally insured limit.
3. Income Taxes; Property Taxes
The Trust is treated
as a partnership for federal and applicable state income tax purposes. For U.S. federal income tax purposes, a partnership is not
a taxable entity and incurs no U.S. federal income tax liability. With respect to state taxation, a partnership is typically treated
in the same manner as it is for U.S. federal income tax purposes. However, the Trust’s activities result in the Trust having
nexus in Texas and, therefore, make it subject to Texas franchise tax. Texas franchise tax is treated as an income tax for financial
statement purposes. The Trust is required to pay Texas franchise tax each year at a maximum effective rate (subject to changes
in the statutory rate) of 0.525% of its gross income, all of which is realized from activities in Texas. The Trust records Texas
franchise tax when paid. The Trust paid its 2018 Texas franchise tax of approximately $0.1 million during the year ended December 31,
2019. The Trust paid its 2017 Texas franchise tax of approximately $0.1 million during the year ended December 31, 2018. The
Trust expects to pay its estimated 2019 Texas franchise tax liability of approximately $0.1 million during the year ending December 31,
2020. Further, the Trust’s tax years 2015 to present remain open for examination with respect to Texas franchise tax.
The Trust records
Texas property taxes when paid. The Trust paid its 2018 property taxes of approximately $1.6 million during the year ended
December 31, 2018. Due to timing issues, the Trust did not make any property tax payments during the year ended December 31,
2019, as it paid its 2019 property taxes of approximately $1.7 million in January 2020.
4. Distributions to Unitholders
The Trust makes quarterly
cash distributions of substantially all of its cash receipts, after deducting amounts for the Trust’s administrative expenses,
property tax and Texas franchise tax and cash reserves withheld by the Trustee, on or about the 60th day following the completion
of each quarter. Distributions cover a three-month production period consisting of the first two months of the most recently ended
quarter and the final month of the preceding quarter. A summary of the Trust’s distributions to unitholders is as follows:
|
|
|
|
|
|
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|
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Total
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|
|
|
|
|
|
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Covered
|
|
|
|
|
|
Distribution
|
|
|
Distribution Per
|
|
|
|
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Production Period
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|
Date Declared
|
|
Date Paid
|
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Paid
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Common Unit
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|
|
|
|
|
|
|
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(in millions)
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|
|
|
|
|
|
Calendar Quarter 2019
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|
|
|
|
|
|
|
|
|
|
|
|
|
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First Quarter
|
|
September 1, 2018 - November 30, 2018
|
|
January 24, 2019
|
|
February 22, 2019
|
|
$
|
5.0
|
|
|
$
|
0.095
|
|
|
Second Quarter
|
|
December 1, 2018 - February 28, 2019
|
|
April 25, 2019
|
|
May 24, 2019
|
|
$
|
3.7
|
|
|
$
|
0.071
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|
|
Third Quarter
|
|
March 1, 2019 - May 31, 2019
|
|
July 24, 2019
|
|
August 23, 2019
|
|
$
|
4.7
|
|
|
$
|
0.089
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|
|
Fourth Quarter
|
|
June 1, 2019 - August 31, 2019
|
|
October 24, 2019
|
|
November 24, 2019
|
|
$
|
3.8
|
|
|
$
|
0.073
|
|
|
|
|
|
|
|
|
|
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|
|
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|
Calendar Quarter 2018
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|
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|
|
|
|
|
|
|
|
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First Quarter
|
|
September 1, 2017 - November 30, 2017
|
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January 25, 2018
|
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February 23, 2018
|
|
$
|
5.9
|
|
|
$
|
0.113
|
|
|
Second Quarter
|
|
December 1, 2017 - February 28, 2018
|
|
April 26, 2018
|
|
May 25, 2018
|
|
$
|
6.6
|
|
|
$
|
0.125
|
|
|
Third Quarter
|
|
March 1, 2018 - May 31, 2018
|
|
July 26, 2018
|
|
August 24, 2018
|
|
$
|
6.8
|
|
|
$
|
0.129
|
|
|
Fourth Quarter
|
|
June 1, 2018 - August 31, 2018
|
|
October 25, 2018
|
|
November 23, 2018
|
|
$
|
6.0
|
|
|
$
|
0.115
|
|
On February 28,
2020, the Trust paid a cash distribution of $4.2 million covering production for the period from September 1, 2019 to November 30,
2019. See Note 8 for further discussion.
5. Commitments and Contingencies
Loan Commitment.
Pursuant to the trust agreement, if at any time the Trust’s cash on hand (including available cash reserves) is not sufficient
to pay the Trust’s ordinary course administrative expenses as they become due, Avalon will, at the Trustee’s request,
loan funds to the Trust necessary to pay such expenses. Any funds loaned by Avalon pursuant to this commitment will be limited
to the payment of current accounts payable or other obligations to trade creditors in connection with obtaining goods or services
or the payment of other current liabilities arising in the ordinary course of the Trust’s business, and may not be used to
satisfy Trust indebtedness, or to make distributions. If Avalon loans funds pursuant to this commitment, unless Avalon agrees otherwise,
no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution
amount) until such loan is repaid. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially
the same as those which would be obtained in an arm’s length transaction between Avalon and an unaffiliated third party.
No such loan from Avalon was outstanding at December 31, 2019 or 2018.
Risks and Uncertainties.
The Trust’s revenue and distributions are substantially dependent upon the prevailing and future prices for oil and natural
gas, each of which depends on numerous factors beyond the Trust’s control such as overall oil and natural gas production
and inventories in relevant markets, economic conditions, the global political environment, regulatory developments and competition
from other energy sources. Oil and natural gas prices historically have been volatile, and may be subject to significant fluctuations
in the future. Low levels of future production and continued low commodity prices would continue to reduce the Trust’s revenues
and distributable income available to unitholders.
The Trust is highly
dependent on Avalon for multiple services, including the operation of the Trust wells, remittance of net proceeds from the sale
of associated production to the Trust, administrative services such as accounting, tax preparation, bookkeeping and informational
services performed on behalf of the Trust, and potentially for loans to pay Trust administrative expenses. Avalon is a relatively
new oil and gas company formed in August 2018 with no prior operating history. Avalon’s ability to continue operating
the properties depends on its future financial condition and economic performance, access to capital, and other factors, many
of which are out of Avalon's control.
6. Related Party Transactions
Trustee Administrative
Fee. Under the terms of the trust agreement, the Trust pays an annual administrative fee to the Trustee, which prior to
2017 was $150,000. The annual administrative fee can be adjusted for inflation by no more than 3% in any year. The Trustee’s
administrative fees paid during the years ended December 31, 2019 and 2018 totaled approximately $158,000 and $155,000, respectively.
Registration Rights
Agreement. The Trust is party to a registration rights agreement pursuant to which the Trust has agreed to register the
offering of the Trust units now held by Avalon upon request by Avalon. The holders have the right to require the Trust to file
no more than five registration statements in aggregate, one of which has been filed to date. The Trust does not bear any expenses
associated with such transactions.
Administrative Services
Agreement. The Trust is party to an Administrative Services Agreement with Avalon (as the assignee of SandRidge) that
obligates the Trust to pay Avalon an annual administrative services fee for accounting, tax preparation, bookkeeping and informational
services performed by Avalon on behalf of the Trust. For its services under the Administrative Services Agreement, Avalon receives
an annual fee of $300,000, which is payable in equal quarterly installments and will remain fixed for the life of the Trust. Avalon
is also entitled to receive reimbursement for its out-of-pocket fees, costs and expenses incurred in connection with the provision
of any of the services under the Administrative Services Agreement. The Administrative Services Agreement will terminate on the
earliest to occur of: (i) the date the Trust shall have dissolved and commenced winding up in accordance with the Trust Agreement,
(ii) the date that all of the Royalty Interests have been terminated or are no longer held by the Trust, (iii) pertaining
to services to be provided with respect to any Underlying Properties transferred by Avalon, the date that either Avalon or the
Trustee may designate by delivering 90-days’ prior written notice, provided that the transferee of such Underlying Properties
assumes responsibility to perform the services in place of Avalon and (iv) a date mutually agreed by Avalon and the Trustee.
During the year ended December 31, 2019 the Trust paid administrative fees in the amount of $75,000 to SandRidge, as provided
under the Transition Services Agreement between SandRidge and Avalon, and $225,000 to Avalon. During the year ended December 31,
2018, the Trust paid administrative fees in the amount of $300,000 to SandRidge.
7. Major Customers
For the years ended
December 31, 2019 and 2018, sales of production attributable to the Royalty Interests exceeding 10% of the Trust’s total
revenues were made to the following oil or natural gas purchasers:
|
|
|
Sales
|
|
|
% of Revenue
|
|
|
|
|
(in thousands)
|
|
|
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
Enterprise Crude Oil LLC
|
|
$
|
17,063
|
|
|
|
81.2
|
%
|
|
ConocoPhillips Company
|
|
$
|
3,951
|
|
|
|
18.8
|
%
|
|
2018
|
|
|
|
|
|
|
|
|
|
Enterprise Crude Oil LLC
|
|
$
|
22,685
|
|
|
|
76.0
|
%
|
|
ConocoPhillips Company
|
|
$
|
4,917
|
|
|
|
16.5
|
%
|
In October 2019,
Avalon entered into a crude oil purchasing agreement with Ace Gathering Inc., a Texas corporation doing business as Ace Energy
Solutions (“ACE”). Pursuant to the terms of the contract, Avalon is required to deliver all crude oil produced
from wells it operates, including the Underlying Properties, beginning November 1, 2019. As a result, all production from
the Underlying Properties is committed to ACE under the contract through December 31, 2021. The price for each barrel of
crude oil delivered under the contract is NYMEX West Texas Intermediate averaged over the month of delivery, subject to certain
adjustments as set forth in the contract. Avalon entered into this contract, together with an agreement whereby Avalon can purchase
condensate from ACE to use in its well workover program, in order to maximize the price of production, as well as the transparency
of pricing, from the Underlying Properties and other properties operated by Avalon. Transportation of crude oil sold by Avalon
will continue to utilize existing pipeline systems and suppliers, including Enterprise Crude Oil LLC and ConocoPhillips Company.
8. Subsequent Events
On January 23,
2020, the Trust declared a cash distribution of $0.080 per unit covering production for the three-month period from September 1,
2019 to November 30, 2019 for record unitholders as of February 14, 2020. A distribution of $4.2 million was paid on
February 28, 2020. Distributable income for September 1, 2019 to November 30, 2019 was calculated as follows (in
thousands, except for unit and per unit amounts):
|
Revenues
|
|
|
|
|
|
Royalty income
|
|
$
|
5,273
|
|
|
Total revenues
|
|
|
5,273
|
|
|
Expenses
|
|
|
|
|
|
Post-production expenses
|
|
|
15
|
|
|
Production taxes
|
|
|
254
|
|
|
Cash reserves withheld by Trustee(1)
|
|
|
620
|
|
|
Total expenses
|
|
|
889
|
|
|
Distributable income
|
|
$
|
4,384
|
|
|
Additional cash reserve(2)
|
|
|
190
|
|
|
Distributable income available to unitholders
|
|
$
|
4,194
|
|
|
Distributable income per unit (52,500,000 units issued and outstanding)
|
|
$
|
0.080
|
|
(1) Includes amounts withheld for
payment of future Trust administrative expenses.
(2) Cash reserve increase for the
payment of future known, anticipated or contingent expenses or liabilities.
9. Supplemental Information on Oil and Natural Gas Producing
Activities (Unaudited)
The following supplemental
information includes capitalized costs related to oil and natural gas producing activities; costs incurred in oil and natural gas
property acquisition, exploration and development; and the results of operations for oil and natural gas producing activities.
Supplemental information is also provided for oil, natural gas and NGL production and average sales prices; the estimated quantities
of proved oil, natural gas and NGL reserves; the standardized measure of discounted future net cash flows associated with proved
oil, natural gas and NGL reserves; and a summary of the changes in the standardized measure of discounted future net cash flows
associated with proved oil, natural gas and NGL reserves. This supplemental information was prepared on an accrual basis, which
is the basis upon which Avalon, Sandridge, and the Underlying Properties maintained their records and is different from the modified
cash basis on which the Trust’s financial statements are prepared. A reconciliation of information presented on the modified
cash basis to the accrual basis for the years ended December 31, 2019 and 2018 is as follows:
|
|
|
Year Ended December 31, 2019
|
|
|
|
|
|
|
|
For the period
|
|
|
|
|
|
|
|
Modified Cash
Basis(1)
|
|
|
September 1, 2018
to
December 31, 2018
|
|
|
September 1, 2019
to
December 31, 2019
|
|
|
Accrual Basis
(2)
|
|
|
Production Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
422.0
|
|
|
|
(146.1
|
)
|
|
|
138.7
|
|
|
|
415.0
|
|
|
NGL (MBbls)
|
|
|
57.0
|
|
|
|
(21.2
|
)
|
|
|
13.8
|
|
|
|
49.6
|
|
|
Natural Gas (MMcf)
|
|
|
181.2
|
|
|
|
(67.2
|
)
|
|
|
48.2
|
|
|
|
162.2
|
|
|
Combined equivalent volumes (MBoe)(3)
|
|
|
509.2
|
|
|
|
(178.5
|
)
|
|
|
160.6
|
|
|
|
491.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty Income (in thousands)
|
|
$
|
22,374
|
|
|
$
|
(7,887
|
)
|
|
$
|
7,109
|
|
|
$
|
21,596
|
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-production costs
|
|
|
50
|
|
|
|
2
|
|
|
|
2
|
|
|
|
54
|
|
|
Property taxes
|
|
|
—
|
|
|
|
(43
|
)
|
|
|
1,719
|
|
|
|
1,676
|
|
|
Production taxes
|
|
|
1,061
|
|
|
|
(375
|
)
|
|
|
335
|
|
|
|
1,021
|
|
|
|
|
$
|
21,263
|
|
|
$
|
(7,471
|
)
|
|
$
|
5,053
|
|
|
$
|
18,845
|
|
|
|
|
Year Ended December 31, 2018
|
|
|
|
|
|
|
|
For the period
|
|
|
|
|
|
|
|
Modified Cash
Basis(4)
|
|
|
September 1, 2017 to
December 31, 2017
|
|
|
September 1, 2018
to
December 31, 2018
|
|
|
Accrual Basis
(2)
|
|
|
Production Data (Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil (MBbls)
|
|
|
485.0
|
|
|
|
(168.3
|
)
|
|
|
146.1
|
|
|
|
462.8
|
|
|
NGL (MBbls)
|
|
|
72.3
|
|
|
|
(25.4
|
)
|
|
|
21.2
|
|
|
|
68.1
|
|
|
Natural Gas (MMcf)
|
|
|
227.3
|
|
|
|
(82.3
|
)
|
|
|
67.2
|
|
|
|
212.2
|
|
|
Combined equivalent volumes (MBoe)(3)
|
|
|
595.2
|
|
|
|
(207.4
|
)
|
|
|
178.5
|
|
|
|
566.3
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty Income (in thousands)
|
|
$
|
29,806
|
|
|
$
|
(9,472
|
)
|
|
$
|
7,887
|
|
|
$
|
28,221
|
|
|
Expenses (in thousands):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Post-production costs
|
|
|
46
|
|
|
|
(1
|
)
|
|
|
(2
|
)
|
|
|
45
|
|
|
Property taxes
|
|
|
1,559
|
|
|
|
(43
|
)
|
|
|
43
|
|
|
|
1,559
|
|
|
Production taxes
|
|
|
1,423
|
|
|
|
(451
|
)
|
|
|
375
|
|
|
|
1,347
|
|
|
|
|
$
|
26,778
|
|
|
$
|
(8,977
|
)
|
|
$
|
7,471
|
|
|
$
|
25,270
|
|
(1) Production
volumes attributable to the Royalty Interests and related revenues and expenses included in Avalon’s net revenue distributions
to the trust represents production from September 1, 2018 to August 31, 2019.
(2) Production
volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis for the years ended
December 31, 2019 and 2018 respectively.
(3) Barrel
of oil equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, which approximates the relative energy
content of oil as compared to natural gas.
(4) Production volumes attributable to the Royalty Interests and related revenues
and expenses included in SandRidge’s 2018 net revenue distributions to the Trust represents production from September 1,
2017 to August 31, 2018.
Capitalized Costs Related to Oil and Natural Gas
Producing Activities
The Trust’s capitalized costs consisted
of the following (in thousands):
|
|
|
December 31,
|
|
|
|
|
2019
|
|
|
2018
|
|
|
Investment in royalty interests
|
|
|
|
|
|
|
|
|
|
Proved(1)
|
|
$
|
549,831
|
|
|
$
|
549,831
|
|
|
Unproved
|
|
|
—
|
|
|
|
—
|
|
|
Total investment in royalty interests
|
|
|
549,831
|
|
|
|
549,831
|
|
|
Less accumulated amortization and impairment
|
|
|
(447,373
|
)
|
|
|
(436,973
|
)
|
|
Net investment in royalty interests
|
|
$
|
102,458
|
|
|
$
|
112,858
|
|
(1) Royalty Interests
conveyed to the Trust by Avalon were in proved properties only.
Costs Incurred in Oil and
Natural Gas Property Acquisition, Exploration and Development
The Trust is not responsible
for any costs incurred related to the Underlying Properties. As such, the Trust did not incur any costs in the exploration or development
of oil and natural gas properties during the years ended December 31, 2019 or 2018.
Results of Operations for Oil and Natural Gas
Producing Activities (Unaudited)
The Trust’s
results of operations from oil and natural gas producing activities for each of the years ended 2019 and 2018 are shown in the
following table (in thousands):
|
|
|
December 31,(1)
|
|
|
|
|
2019
|
|
|
2018
|
|
|
Revenues
|
|
$
|
21,663
|
|
|
$
|
28,272
|
|
|
Expenses(2)
|
|
|
|
|
|
|
|
|
|
Post-production costs
|
|
|
54
|
|
|
|
45
|
|
|
Property taxes
|
|
|
1,676
|
|
|
|
1,559
|
|
|
Production taxes
|
|
|
1,021
|
|
|
|
1,347
|
|
|
Amortization expense(3)
|
|
|
10,399
|
|
|
|
11,018
|
|
|
Income before income taxes
|
|
|
8,513
|
|
|
|
14,303
|
|
|
Income taxes(4)
|
|
|
36
|
|
|
|
47
|
|
|
Results of operations for oil and natural gas producing activities (excluding general and administrative costs and derivative settlements of the Trust)
|
|
$
|
8,477
|
|
|
$
|
14,256
|
|
(1)
Revenues and post-production costs attributable to volumes produced from January 1 to December 31 of the respective
year, regardless of whether proceeds from the sale of production have been remitted to the Trust by Avalon and SandRidge, respectively.
(2)
The Trust does not bear any well operating costs.
(3)
Amortization is recorded by the Trust as volumes are produced and does not reduce distributable income, but rather, is recorded
directly to trust corpus.
(4)
Reflect Trust’s effective state income tax rate of 0.1655%. The Trust is not required to pay federal income tax.
Oil, Natural Gas and NGL
Reserve Quantities (Unaudited)
Proved reserves are
those quantities of oil, natural gas and NGL, which, by analysis of geoscience and engineering data, can be estimated with reasonable
certainty to be economically producible, based on prices used to estimate reserves, from a given date forward from known reservoirs,
and under existing economic conditions, operating methods, and government regulation before the time of which contracts providing
the right to operate expire, unless evidence indicates that renewal is reasonably certain. Proved developed reserves are proved
reserves expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of
the required equipment is relatively minor compared with the cost of a new well. Proved undeveloped reserves are reserves that
are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively large major expenditure
is required for recompletion.
Netherland, Sewell &
Associates, Inc. (“Netherland Sewell”), independent oil and natural gas consultants, prepared the estimates of
proved reserves of oil, natural gas and NGL attributable to the Royalty Interests. Netherland Sewell are independent petroleum
engineers, geologists, geophysicists and petrophysicists and do not own an interest in the Trust or its properties and are not
employed on a contingent basis.
Based on its review
of the estimates of proved reserves made by the independent petroleum engineers, SandRidge has advised the Trustee that the geoscience
and engineering data examined provides reasonable assurance that the proved reserves are economically producible in future years
from known reservoirs, and under existing economic conditions, operating methods and governmental regulations. Estimates of proved
reserves are subject to change, either positively or negatively, as additional information is available and contractual and economic
conditions change.
The table below represents
the estimate of proved reserves attributable to the Trust’s net interest in oil and natural gas properties, all of which
are located in the continental United States, based upon the evaluation by the Trustee and its independent petroleum engineers
of pertinent geoscience and engineering data in accordance with the SEC’s regulations. Estimates of the Trust’s proved
reserves have been prepared by independent reservoir engineers and geoscience professionals and are reviewed by members of SandRidge’s
senior management with professional training in petroleum engineering to ensure that rigorous professional standards and the reserve
definitions prescribed by the SEC are consistently applied.
The summary below presents
changes in the Trust’s estimated reserves during the years ended December 31, 2019 and 2018.
|
|
|
Oil
(MBbls)
|
|
|
NGL
(MBbls)
|
|
|
Natural Gas
(MMcf)(1)
|
|
|
Proved developed and undeveloped reserves
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2017
|
|
|
4,999.9
|
|
|
|
758.9
|
|
|
|
2,544.4
|
|
|
Revisions of previous estimates
|
|
|
30.4
|
|
|
|
1.0
|
|
|
|
(168.4
|
)
|
|
Extensions and discoveries
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Production(2)
|
|
|
(462.8
|
)
|
|
|
(68.1
|
)
|
|
|
(212.2
|
)
|
|
As of December 31, 2018
|
|
|
4,567.5
|
|
|
|
691.8
|
|
|
|
2,163.8
|
|
|
Revisions of previous estimates
|
|
|
(233.8
|
)
|
|
|
(230.7
|
)
|
|
|
(642.5
|
)
|
|
Extensions and discoveries
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
Production(2)
|
|
|
(415.0
|
)
|
|
|
(49.6
|
)
|
|
|
(162.2
|
)
|
|
As of December 31, 2019
|
|
|
3,918.7
|
|
|
|
411.5
|
|
|
|
1,359.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved developed reserves(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
|
4,567.5
|
|
|
|
691.8
|
|
|
|
2,163.8
|
|
|
As of December 31, 2019
|
|
|
3,918.7
|
|
|
|
411.5
|
|
|
|
1,359.1
|
|
|
Proved undeveloped reserves(3)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As of December 31, 2018
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
As of December 31, 2019
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
(1)
Natural gas reserves are computed at 14.65 pounds per square inch absolute and 60 degrees Fahrenheit.
(2)
Volumes produced from January 1 to December 31 of the respective year, regardless of whether proceeds from the sale
of such production have been remitted to the Trust by SandRidge or Avalon, as applicable.
(3)
Estimated proved reserves were determined using a 12-month average price for oil, natural gas and NGL.
The Trust recognized
net reductions to reserves associated with proved properties of approximately 571.6 MBoe as a result of pricing during 2019. The
Trust recognized net additions to reserves associated with proved properties of approximately 3.3 MBoe due to pricing and well
performance during 2018.
Standardized Measure of Discounted
Future Net Cash Flows (Unaudited)
The assumptions underlying
the computation of the standardized measure of discounted cash flows are summarized as follows:
|
|
•
|
the standardized measure includes estimates of proved oil, natural gas and NGL reserves and projected
future production volumes based upon economic conditions;
|
|
|
•
|
pricing is applied based upon 12-month average market prices at December 31, 2019 and 2018.
The calculated weighted average per unit prices for the Trust’s proved reserves and future net revenues were as follows;
|
|
|
|
December 31,
|
|
|
|
|
2019
|
|
|
2018
|
|
|
Oil (per barrel)
|
|
$
|
51.58
|
|
|
$
|
59.12
|
|
|
NGL (per barrel)
|
|
$
|
19.55
|
|
|
$
|
24.91
|
|
|
Natural Gas (per Mcf)
|
|
$
|
0.88
|
|
|
$
|
1.89
|
|
|
|
•
|
a discount factor of 10% per year is applied annually to the future net cash flows; and
|
|
|
•
|
future income tax expenses are computed based upon the estimated effective state income tax rates
of 0.1655%. The Trust is not required to pay federal income taxes.
|
The summary below presents the Trust’s
future net cash flows relating to proved oil, natural gas and NGL reserves based on the standardized measure in ASC Topic 932 (in
thousands).
|
|
|
As of December 31,
|
|
|
|
|
2019
|
|
|
2018
|
|
|
Future cash inflows from production
|
|
$
|
211,362
|
|
|
$
|
291,358
|
|
|
Future production costs(1)
|
|
|
(16,434
|
)
|
|
|
(22,896
|
)
|
|
Future income taxes
|
|
|
(350
|
)
|
|
|
(482
|
)
|
|
Undiscounted future net cash flows
|
|
|
194,578
|
|
|
|
267,980
|
|
|
10% annual discount
|
|
|
(90,764
|
)
|
|
|
(132,493
|
)
|
|
Standardized measure of discounted future net cash flows
|
|
$
|
103,814
|
|
|
$
|
135,487
|
|
(1) Includes the Trust’s
proportionate share of production taxes and post-production costs. The Trust does not bear any development or operational costs
related to wells.
The following table represents the Trust’s
estimate of changes in the standardized measure of discounted future net cash flows from proved reserves (in thousands):
|
Present value as of December 31, 2017
|
|
$
|
122,983
|
|
|
Revenues less post-production and other costs
|
|
|
(25,269
|
)
|
|
Net changes in prices, production and other costs
|
|
|
27,269
|
|
|
Revisions of previous quantity estimates
|
|
|
716
|
|
|
Accretion of discount
|
|
|
11,217
|
|
|
Net changes in income taxes
|
|
|
(22
|
)
|
|
Timing differences and other(1)
|
|
|
(1,407
|
)
|
|
Net change for the year
|
|
|
12,504
|
|
|
Present value as of December 31, 2018
|
|
$
|
135,487
|
|
|
Revenues less post-production and other costs
|
|
|
(18,843
|
)
|
|
Net changes in prices, production and other costs
|
|
|
(18,032
|
)
|
|
Revisions of previous quantity estimates
|
|
|
(10,641
|
)
|
|
Accretion of discount
|
|
|
12,396
|
|
|
Net changes in income taxes
|
|
|
57
|
|
|
Timing differences and other(1)
|
|
|
3,390
|
|
|
Net change for the year
|
|
|
(31,673
|
)
|
|
Present value as of December 31, 2019
|
|
$
|
103,814
|
|
(1) Changes in timing
differences and other are related to revisions in the estimated timing of production and, as applicable, development.
10. Quarterly Financial Results (Unaudited)
The Trust’s operating results for
each calendar quarter of 2019 and 2018 are summarized below (in thousands, except per unit data).
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
|
|
(1)
|
|
|
(2)
|
|
|
(3)
|
|
|
(4)
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income
|
|
$
|
6,257
|
|
|
$
|
4,901
|
|
|
$
|
6,068
|
|
|
$
|
5,216
|
|
|
Distributable income available to unitholders
|
|
$
|
4,981
|
|
|
$
|
3,780
|
|
|
$
|
4,671
|
|
|
$
|
3,857
|
|
|
Distributable income per common unit
|
|
$
|
0.095
|
|
|
$
|
0.071
|
|
|
$
|
0.089
|
|
|
$
|
0.073
|
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
|
|
(5)
|
|
|
(6)
|
|
|
(7)
|
|
|
(8)
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Royalty income
|
|
$
|
6,925
|
|
|
$
|
7,737
|
|
|
$
|
7,984
|
|
|
$
|
7,211
|
|
|
Distributable income available to unitholders
|
|
$
|
5,935
|
|
|
$
|
6,568
|
|
|
$
|
6,781
|
|
|
$
|
6,042
|
|
|
Distributable income per common unit
|
|
$
|
0.113
|
|
|
$
|
0.125
|
|
|
$
|
0.129
|
|
|
$
|
0.115
|
|
(1)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from September 1, 2018 to November 30,
2018.
(2)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from December 1, 2018 to February 28,
2019.
(3)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from March 1, 2019 to May 31,
2019.
(4)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from June 1, 2019 to August 31,
2019.
(5)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from September 1, 2017 to November 30,
2017.
(6)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from December 1, 2017 to February 28,
2018.
(7)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from March 1, 2018 to May 31,
2018.
(8)
Includes proceeds attributable to production from the wells burdened by the Royalty Interests from June 1, 2018 to August 31,
2018.
