SandRidge Permian Trust - FORM 10-K

Attached files

file	filename
EX-99.1 - EXHIBIT 99.1 - SandRidge Permian Trust	tm211192d1_ex99-1.htm
EX-32.1 - EXHIBIT 32.1 - SandRidge Permian Trust	tm211192d1_ex32-1.htm
EX-31.1 - EXHIBIT 31.1 - SandRidge Permian Trust	tm211192d1_ex31-1.htm
EX-23.1 - EXHIBIT 23.1 - SandRidge Permian Trust	tm211192d1_ex23-1.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2020

TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 001-35274

	SANDRIDGE PERMIAN TRUST
	(Exact name of registrant as specified in its charter)

Delaware		45-6276683
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

The Bank of New York Mellon Trust Company, N.A., Trustee 601 Travis Street, 16^thFloor, Houston, Texas		77002
(Address of principal executive offices)		(Zip Code)

	(512) 236-6555
	(Registrant’s telephone number, including area code)
	Securities registered pursuant to Section 12(b) of the Act:
	None


	Securities registered pursuant to Section 12(g) of the Act:
	None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x

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 has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ¨ 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.

Large accelerated filer ¨	Accelerated filer ¨
Non-accelerated filer x	Smaller reporting company x
	Emerging growth company ¨

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. ¨

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

The aggregate market value of Common Units of Beneficial Interest of the Trust held by non-affiliates on June 30, 2020 (the last business day of its most recently completed second quarter) was approximately $17.72 million based on the closing price as quoted on the New York Stock Exchange.

As of March 26, 2021, 52,500,000 Common Units of Beneficial Interest in SandRidge Permian Trust were outstanding.

DOCUMENTS INCORPORATED BY REFERENCE: None

SANDRIDGE PERMIAN TRUST

2020 ANNUAL REPORT ON FORM 10-K

TABLE OF CONTENTS

Item		Page

PART I

1	Business	1
1A.	Risk Factors	26
1B.	Unresolved Staff Comments	48
2	Properties	48
3	Legal Proceedings	48
4	Mine Safety Disclosures	48

PART II

5	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	49
6	Selected Financial Data	50
7	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations	50
7A	Quantitative and Qualitative Disclosures about Market Risk	57
8	Financial Statements and Supplementary Data	57
9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	57
9A	Controls and Procedures	57
9B	Other Information	58

PART III

10	Directors, Executive Officers and Corporate Governance	59
11	Executive Compensation	59
12	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	59
13	Certain Relationships and Related Transactions, and Director Independence	60
14	Principal Accountant Fees and Services	60

PART IV

15	Exhibit and Financial Statement Schedules	61
16	Form 10-K Summary	61

INTRODUCTION

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.

FORWARD-LOOKING STATEMENTS

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, information regarding costs and information regarding production and reserve declines, 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. The Trust has based these forward-looking statements on its current expectations and assumptions about future events. These statements are based on certain assumptions made by the Trust in light of its experience and its perception of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. However, whether actual results and developments will conform with the Trust’s 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.

iii

GLOSSARY OF OIL AND NATURAL GAS TERMS

The following is a description of the meanings of some of the oil and natural gas industry terms used in this report.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used in this report in reference to oil or other liquid hydrocarbons.

Boe. Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil. Although an equivalent barrel of condensate or natural gas may be equivalent to a barrel of oil on an energy basis, it is not equivalent on a value basis as there may be a large difference in value between an equivalent barrel and a barrel of oil.

Boe/d. Barrels of oil equivalent per day.

Developed oil and natural gas reserves. Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Gross wells. The total wells in which a working interest is owned.

LOE. Leasehold operating expenses.

MBbls. Thousand barrels of oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent.

MBoe/d. Thousand barrels of oil equivalent per day.

Mcf. Thousand cubic feet of natural gas.

MMcf. Million cubic feet of natural gas.

Net wells. The sum of the fractional working interests owned in gross wells.

Net revenue interests or NRI. A share of production after all burdens, such as royalties and overriding royalty interests, have been deducted from the working interest.

NGL. Natural gas liquids, such as ethane, propane, butanes and natural gasolines that are extracted from natural gas production streams.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Texas regulations require plugging of abandoned wells.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities that become part of the cost of oil, natural gas and NGL produced.

Productive well. A well that is found to be capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well.

Proved reserves. 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. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

PV-10. The present value of estimated future revenues to be generated from the production of proved reserves, before income taxes, calculated in accordance with SEC guidelines, net of estimated production and future development costs, using prices and costs as of the date of estimation without future escalation and without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization. PV-10 is calculated using an annual discount rate of 10%.

Reserves. Estimated remaining quantities of oil, natural gas and NGL and related substances anticipated to be economically producible by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil, natural gas and NGL or related substances to market, and all permits and financing required to implement the project.

Standardized measurement. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, discounted at 10% per annum to reflect timing of future cash flows and using the same pricing assumptions as were used to calculate PV-10. Standardized Measure differs from PV-10 because Standardized Measure includes the effect of future income taxes on future net revenues.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

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, 16^th 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: https://per.q4web.com/home/default.aspx. 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 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 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. At March 26, 2021, the Trust had 52,500,000 Common Units issued and outstanding.

The Trust is passive in nature and neither the Trust nor the Trustee has any control over, or responsibility for, or involvement with, any aspect of the oil and natural gas operations, operating or capital costs or other activities 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 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 resulting reduction in the benchmark price of crude oil persist for the near term or longer, such factor is 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.

Sale of Assets by SandRidge to Avalon. 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 (“Avalon Energy”). In connection with this transaction (the “Sale Transaction”), Avalon Energy assumed all of SandRidge’s obligations under the Trust Agreement, the Conveyances, and the administrative services agreement between SandRidge and the Trust (as further described below). Avalon Energy, together with Avalon Exploration and Production LLC, its parent company, and Avalon TX Operating, LLC, the operator of the Underlying Properties, are collectively referred to as “Avalon” in this report. As a part of the Sale Transaction, SandRidge provided certain transition services to Avalon, including trust administration services, through April 30, 2019, pursuant to a transition services agreement that expired at the end of the transition period. At December 31, 2020, Avalon owned 13,125,000 Common Units, or 25% of all issued and outstanding Trust units.

In connection with the Sale Transaction, Avalon obtained a revolving line of credit from Washington Federal Bank, National Association (“WaFed”) pursuant to the terms of a Loan Agreement and related security documents (the “WaFed Loan”). Avalon used the proceeds of the WaFed Loan to fund a portion of the purchase price for the Underlying Properties and Trust units acquired in the Sale Transaction. The WaFed Loan is secured by a first lien mortgage on Avalon’s interest in the Underlying Properties and a pledge of the Avalon Trust units (the “WaFed Collateral”). The Trust’s Royalty Interests are not part of the WaFed Collateral.

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 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. In addition, the Trust Agreement and Conveyances permit Avalon to sell any part of its interest in the Underlying Properties free from and unburdened by the Royalty Interests, without the consent of the Trustee or Trust unitholders, provided (a) the Trust receives fair value in the form of cash for the Royalty Interests to be released by the Trustee in connection with the sale of the Underlying Properties, (b) the aggregate fair value of the Royalty Interests to be released by the Trustee and any other Royalty Interests previously released by the Trustee during the most recently completed 12 calendar months would not exceed $5 million and (c) the Trustee shall have received a certificate from Avalon certifying to the Trustee and the Trust that the cash proceeds to be received by the Trust in respect of the Royalty Interest to be released in connection with the sale of the Underlying Properties represents fair value to the Trust for such Royalty Interests.

Delisting of Trust Units. On December 27, 2019, the Trust received written notification from The New York Stock Exchange (“NYSE”) that the Trust no longer satisfied the continued listing compliance standards set forth under Rule 802.01C of the NYSE Listed Company Manual because the average closing price of the Trust units fell below $1.00 over a 30 consecutive trading-day period. As the Trust was unable to regain compliance with the applicable standards within an extended cure period, the NYSE announced the suspension of trading of the Trust units due to non-compliance with Section 802.01C of the NYSE Listed Company Manual, effective as of the close of trading on September 8, 2020, and announced that it was initiating proceedings to delist the Trust units. As a result, the Trust units transitioned to the OTC Pink Market, operated by OTC Markets Group, effective with the opening of trading on September 9, 2020 under the trading symbol “PERS.” On September 28, 2020, the NYSE filed a Form 25 to delist the Trust units, which became effective on October 9, 2020. A trading market for the Trust units might not continue to exist on the OTC Pink Market. Moreover, current trading levels might not be sustained or could diminish.

The May 2020 Quarterly Payment. In April 2020, Avalon informed the Trustee that Avalon had been using its commercially reasonable efforts to preserve the oil and gas leases burdened by the Royalty Interests so that in the future, assuming that oil prices returned to a profitable level, the Trust would still hold its Royalty Interests, and Trust unitholders might have the opportunity to receive future quarterly distributions. Avalon also informed the Trustee that it believed that continuing production from those Trust Wells required to preserve such leases was preferable to stopping production, as the failure to continue production would result in a termination of Avalon’s working interest in such Trust Wells and, therefore, the Royalty Interests, which would have a material adverse effect on the Trust’s financial condition. Avalon reported to the Trustee that Avalon therefore used revenues it received during the production period from December 1, 2019 to February 29, 2020 to pay the operating expenses necessary to maintain production from the Trust Wells and to pay oil and gas lessor royalties, as the proceeds attributable to Avalon’s net revenue interest in the Underlying Properties was insufficient to cover all such costs. Avalon had anticipated that revenues from production during the quarterly production period commencing March 1, 2020 would be sufficient to fund the quarterly payment to the Trust for the quarter ended March 31, 2020 in the amount of approximately $4.65 million (the “May 2020 Quarterly Payment”); however, revenues from production during that quarterly production period were insufficient to generate the cash needed to make the May 2020 Quarterly Payment to the Trust due to the sharp drop in crude oil prices during the first quarter of 2020. Consequently, the Trustee was unable to make any quarterly distribution to unitholders at the end of May 2020. In accordance with Section 5.02 of the Conveyances, the unpaid May 2020 Payment amount due and owing to the Trust has been accruing interest since May 15, 2020 at the rate of interest per annum publicly announced from time to time by The Bank of New York Mellon Trust Company, N.A. as its “prime rate” in effect at its principal office in New York City until paid to the Trust. The accrued interest from May 15, 2020 to December 31, 2020 was approximately $94,000. As of December 31, 2020, Avalon had not paid any of the May 2020 Quarterly Payment, or any interest accrued thereon through such date, to the Trust.

On March 1, 2021, the Trust and Avalon entered into a repayment agreement setting forth the terms by which Avalon has agreed to pay the May 2020 Quarterly Payment to the Trust, together with accrued interest (the “Repayment Agreement”). Beginning with the quarterly distribution paid to Trust unitholders on or about February 26, 2021 (the “February Distribution”), Avalon will apply towards the payment of the May 2020 Quarterly Payment the full amount of each quarterly cash distribution, if any, to which Avalon, as a unitholder of the Trust, is entitled (each such cash distribution, a “Company Distribution Amount”), until the May 2020 Quarterly Payment, together with accrued interest, has been paid in full to the Trust, subject to any obligations Avalon may have to repay the WaFed Loan that are not waived as provided in the Repayment Agreement. Promptly upon receipt, Avalon deposited the $984,375 received as its portion of the February Distribution into a repayment account established by the Trustee on behalf of the Trust (the “Repayment Account”) pursuant to the terms of the Repayment Agreement. Avalon will deposit each additional Company Distribution Amount into the Repayment Account promptly, but in no event later than the next business day, after the Company’s receipt of any such Company Distribution Amount.

The Repayment Agreement also provides that if any third party agrees to acquire Avalon, whether pursuant to a merger, consolidation, purchase of all or substantially all of the assets of Avalon, or other similar transaction or series of transactions (an “Avalon Sale Transaction”), then, subject to any obligations Avalon may have to repay the WaFed Loan in connection with any such transaction that is not waived as provided in the Repayment Agreement, Avalon will pay to the Trust from cash received in an Avalon Sale Transaction an amount equal to (i) the difference between (A) the aggregate amounts deposited in the Repayment Account pursuant to the Agreement at the time the Avalon Sale Transaction is consummated and (B) the then outstanding balance of the May 2020 Quarterly Payment together with all accrued and unpaid interest thereon to the date of payment of such outstanding balance (the “Balance Amount”) or (ii) where the amount of cash received in the Avalon Sale Transaction is less than the Balance Amount, all of the cash received in the Avalon Sale Transaction. Avalon agrees that it will pay such amount to the Trust promptly, but in no event later than the next business day, after the closing of any such Avalon Sale Transaction. If Avalon is unable to pay the Balance Amount in full upon the closing of an Avalon Sale Transaction, Avalon has agreed, subject to any obligations Avalon may have to repay the WaFed Loan in connection with any such transaction that are not waived as provided in the Repayment Agreement, to pledge to the Trust, to secure the payment of the outstanding portion of the Balance Amount, any non-cash consideration that Avalon receives from such Avalon Sale Transaction or similar transaction.

Avalon’s Financial Condition. The reduced demand for crude oil in the global market resulting from the economic effects of the COVID-19 pandemic and the dramatic reduction from mid-February to late April 2020 in the benchmark price of crude oil, which continued to fluctuate throughout 2020 and into 2021, have had a negative impact on Avalon’s financial condition. Avalon has informed the Trustee that during 2020 Avalon shut in oil and gas wells subject to the Royalty Interests (“Trust Wells”) that are not capable of producing oil and natural gas in paying quantities, as permitted under the Conveyances, in an effort to further reduce leasehold operating expenses (“LOE”). These Trust Wells were not necessary to hold the leasehold interests burdened by the Trust’s Royalty Interests. Avalon shut in 139 Trust Wells and 114 Trust Wells during the twelve-month periods ended December 31, 2019 and 2020, respectively.

Given Avalon’s financial condition, the Board of Managers of Avalon decided to explore strategic alternatives with respect to its assets, including the Underlying Properties and the Avalon Trust units. In April 2020, Avalon began discussions with WaFed regarding forbearance of certain breached financial covenants and an extension of the WaFed Loan. After a number of discussions regarding a possible transaction with potential strategic partners, on July 30, 2020, Avalon entered into a letter agreement with Montare Resources I, LLC, a Texas limited liability company (“Montare”), agreeing to negotiate exclusively with Montare regarding a possible sale of Avalon assets, including the Underlying Properties, to Montare and supporting Montare in any transaction negotiated with the Trust with respect to the acquisition of all Trust units not owned by Montare. On the same date, Avalon and WaFed entered into an amendment to the WaFed Loan that extended the date on which Avalon was obligated to provide a reserve report to WaFed (regarding the redetermination of the borrowing base) to September 15, 2020 and required Avalon to pay off the WaFed Loan by October 15, 2020. In addition, WaFed and Montare entered into a Participation Agreement with respect to the WaFed Loan whereby Montare purchased an undivided participation interest in the WaFed Loan and has the right to purchase the WaFed Loan in the event Avalon does not meet the conditions of the amended WaFed Loan.

On August 26, 2020, Montare, Avalon and certain of their respective affiliates entered into a Contribution and Support Agreement, pursuant to which Avalon, among other things, (i) agreed, subject to certain conditions, to contribute all of the assets held by Avalon and its affiliates, including the Underlying Properties and the Avalon Trust units, to Montare in exchange for interests in Montare or an affiliate thereof (the “Contribution Transaction”), (ii) agreed to support Montare’s acquisition of all of the issued and outstanding Trust units not owned by Avalon by means of a transaction with the Trust or as otherwise determined by Montare in its sole discretion (the “Montare Transaction”), and any related actions taken by Montare with respect to the Montare Transaction, including by exercising any of Avalon’s rights under the Trust Agreement, (iii) granted exclusivity and an irrevocable proxy to Montare to vote all Trust units beneficially owned by Avalon in connection with the Montare Transaction, and (iv) to not take any action that, directly or indirectly, is detrimental to or hinders Montare’s ability to consummate the Montare Transaction. The consummation of the Contribution Transaction is subject to certain conditions, including Montare’s determination in its sole and absolute discretion that all conditions necessary for the consummation of the Montare Transaction have been satisfied or waived. After preliminary discussions between Montare and representatives of the Trust regarding the Montare Transaction ended (as previously reported by Avalon and Montare in Amendment No. 3 to their joint Schedule 13D filed on September 8, 2020 and by the Trust in its Form 8-K filed on September 8, 2020), Montare and Avalon amended the Contribution and Support Agreement effective October 12, 2020. As amended, this agreement contemplates a sale of Avalon assets having a value of less than $5.0 million, in accordance with the terms of the Trust Agreement, to Montare free from and unburdened by the applicable portion of the Royalty Interests held by the Trust.

Sale of Assets by Avalon to Montare. On October 12, 2020, Montare and Avalon entered into a Purchase and Sale Agreement, effective as of September 1, 2020, whereby Avalon sold wells and related assets associated with certain Underlying Properties to Montare, unburdened by the applicable portion of the Royalty Interests held by the Trust, for approximately $4.9 million in accordance with Avalon’s contractual rights set forth in the Trust Agreement and the Conveyances (the “Montare Sale”). Prior to the Montare Sale, Avalon engaged an independent petroleum engineering firm to determine the fair value of substantially all wells burdened by the Trust’s Royalty Interests (the “Trust Wells”). A copy of the independent petroleum engineering firm’s valuation report has been provided to the Trustee. Avalon informed the Trustee that Avalon then sold to Montare those Trust Wells having a collective value of approximately $4.9 million, retaining ownership of the 65 most valuable Trust Wells burdened by Royalty Interests. The wells sold to Montare include 483 shut-in wells and 338 other wells with negative present value and 428 wells with positive present value. The wells sold to Montare represented approximately 76% of production attributable to the Trust's Royalty Interests for the month ended May 31, 2020 (the most recent month prior to the sale for which production data was available). The Royalty Interests released by the Trust in connection with the Montare Sale represented approximately 32% of the fair value of the Royalty Interests at September 1, 2020.

As previously reported by the Trust in its Form 8-K filed October 14, 2020, Avalon notified the Trust of the Montare Sale on October 13, 2020. As required by the terms of the Trust Agreement, an officer of Avalon certified to the Trust that (i) the gross purchase price received by Avalon for the sale of the specified Trust Wells was less than $5 million and (ii) the cash proceeds received by the Trust in respect of the Royalty Interests to be released in connection with such sale represents Fair Value (as defined in the Trust Agreement) to the Trust for such Royalty Interests. The Montare Sale was completed on October 13, 2020, and all of the approximately $4.9 million of proceeds that Avalon received from such sale were paid to the Trust as fair value for the Royalty Interests required to be released by the Trustee in connection with the Montare Sale in accordance with Section 3.02 of the Trust Agreement. On February 26, 2021, the Trust distributed net sales proceeds of approximately $3.9 million, which represented the amount paid to the Trust by Avalon as fair value for the Royalty Interests required to be released less approximately $884,000 withheld by the Trustee toward its targeted cash reserve, to Trust unitholders in accordance with the terms of the Conveyances granting the Royalty Interests to the Trust. As provided in the Trust Agreement, the sales proceeds of approximately $4.9 million received by the Trust from Avalon is not included in the calculation of the cash available for distribution from royalty payments by Avalon and, therefore, did not affect the timing of the dissolution of the Trust as discussed below under “—Early Termination of the Trust; Sale of Trust Assets.”

On October 30, 2020, Avalon and WaFed entered into another amendment to the WaFed Loan that (i) extends the date by which Avalon is required to provide a reserve report of an independent petroleum engineer to WaFed (regarding the redetermination of the borrowing base) to April 15, 2021, (ii) requires Avalon to pay off the WaFed Loan by April 15, 2021, and (iii) provides a partial release of Trust Wells located on certain of the Underlying Properties in connection with the Montare Sale. In addition, WaFed and Montare modified the Participation Agreement, and Montare purchased an additional interest in the WaFed Loan.

Early Termination of the Trust; Sale of Trust Assets. The Trust Agreement requires the Trust to dissolve and commence winding up of its business and affairs if cash available for distribution for any four consecutive quarters, on a cumulative basis, is less than $5.0 million. Cash available for distribution for the four consecutive quarters ended December 31, 2020, on a cumulative basis, totaled approximately $2.4 million, due in part to Avalon’s inability to make the May 2020 Quarterly Payment to the Trust. Because Avalon’s inability to make the May 2020 Quarterly Payment contributed to the insufficient cumulative cash available for distribution over the four-quarter period, the Trustee and Avalon submitted to an arbitration panel, in accordance with the Trust Agreement, the question of whether the Trust nonetheless remains required to dissolve following the end of that period. On February 25, 2021, the arbitration panel determined that the existence of the unpaid May 2020 Quarterly Payment does not alter the requirement of the Trust to terminate under the provisions of the Trust Agreement. As a result, the Trust was required to dissolve and commence winding up beginning as of the close of business on February 26, 2021.

Accordingly, the Trustee is required to sell all of the Trust’s assets, 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, which is expected to include the establishment of cash reserves in such amounts as the Trustee in its discretion deems appropriate for the purpose of making reasonable provision for all claims and obligations of the Trust, including any contingent, conditional or unmatured claims and obligations, in accordance with the Delaware Statutory Trust Act. The sale process will involve costs that will reduce the amounts of any distributions to Trust unitholders during the winding up period. As required by the Trust Agreement, the Trustee has engaged a third-party advisor to assist with the marketing and sale of the Royalty Interests. As provided in the Trust Agreement, Avalon has a right of first refusal with respect to any sale of Royalty Interests to a third party. The Trustee expects to complete the sale of the Royalty Interests by the end of the third quarter of 2021 and distribute the net proceeds of the sale (together with any cash reserves in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities of the Trust) to the Trust unitholders on the following quarterly payment date, and the Trust units are expected to be canceled shortly thereafter. Pending the sale or sales of the Royalty Interests, and subject to the effective date and other terms of such sale or sales, the Trust anticipates that it will continue to receive income, if any, attributable to the Royalty Interests and will continue to make quarterly distributions to Trust unitholders to the extent there is available cash after payment of Trust expenses and additions to cash reserves. The Trust will remain in existence until the filing of a certificate of cancellation with the Secretary of State of the State of Delaware following the completion of the winding up process.

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 Energy, LLC, as assignee of SandRidge (the “Administrative Services Agreement”), that obligates the Trust to pay Avalon E&P 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 E&P 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 E&P 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 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:

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;

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

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:

have been sold pursuant to Rule 144 under the Securities Act if the transferee thereof does not receive “restricted securities”;

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

become eligible for resale pursuant to Rule 144 (or any similar rule then in effect under the Securities Act).

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:

increase the power of the Trustee to engage in business or investment activities;

alter the rights of the Trust unitholders as among themselves; or

permit the Trustee to distribute the Royalty Interests in kind.

Amendments to the Trust Agreement’s provisions addressing the following matters may not be made without Avalon’s consent:

dispositions of the Trust’s assets;

indemnification of the Trustee;

reimbursement of out-of-pocket expenses of Avalon when acting as the Trust’s agent;

termination of the Trust; and

amendments of the Trust Agreement.

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:

collecting cash proceeds attributable to the Royalty Interests;

paying expenses, charges and obligations of the Trust from the Trust’s assets;

making cash distributions to the Trust unitholders in accordance with the Trust Agreement;

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

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.

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:

interest-bearing obligations of the United States government;

money market funds that invest only in United States government securities;

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

bank certificates of deposit.

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:

prosecute or defend, and settle, claims of or against the Trust or its agents;

retain professionals and other third parties to provide services to the Trust;

charge for its services as Trustee;

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);

lend funds at commercial rates to the Trust to pay the Trust’s expenses; and

seek reimbursement from the Trust for its out-of-pocket expenses.

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.

The Trust Agreement further provides that Avalon (as successor in interest to SandRidge) and its affiliates can discharge their obligations as set forth in the Trust Agreement, the Conveyances, and the Administrative Services Agreement fully, without hinderance or regard to conflict of interest principles, duty of loyalty principles or other breach of fiduciary duties. The Trust Agreement further provides that (a) the other parties to such agreements and the Trust unitholders expressly waive any defenses, claims or assertions with respect to such duties, (b) neither Avalon or its affiliates shall be a fiduciary with respect to the Trust or the Trust unitholders, and (c) to the extent that, at law or in equity, Avalon or its affiliates have duties (including fiduciary duties) and liabilities relating thereto to the Trust or to the Trust unitholders, such duties and liabilities are thereby eliminated to the fullest extent permitted by law.

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:

the sale is requested by Avalon in accordance with the provisions of the Trust Agreement; or

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.

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. The Trust Agreement provides that Avalon has a right of first refusal with respect to such Royalty Interests. 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 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:

the price paid for oil, natural gas and NGL produced in Andrews County, Texas;

the volume of oil, natural gas and NGL produced and sold by Avalon and attributable to the Royalty Interests;

post-production costs (which includes internal costs and third person costs incurred by Avalon, including transportation) 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 5 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. The Trust has not requested and Avalon has not made any such loan to the Trust as of December 31, 2020. Given Avalon’s present financial condition, it does not have the financial resources to make a loan to the Trust if so requested.

Properties

As of December 31, 2019 and 2018, 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 produce primarily oil from the Grayburg and San Andres formations in the Permian Basin.

On October 12, 2020, Montare and Avalon concluded the Montare Sale as discussed above in “General—Sale of Assets by Avalon to Montare.” Prior to the Montare Sale, Avalon engaged an independent petroleum engineering firm to determine the fair value of substantially all wells burdened by the Trust’s Royalty Interests. Avalon informed the Trust that Avalon then sold to Montare those Trust Wells having a collective value of approximately $4.9 million, retaining ownership of the 65 most valuable Trust Wells burdened by Royalty Interests. The wells sold to Montare include 483 shut-in wells and 338 other wells with negative present value and 428 wells with positive present value. The wells sold to Montare represented approximately 76% of production attributable to the Trust's Royalty Interests for the month ended May 31, 2020 (the most recent month prior to the sale for which production data was available). The Royalty Interests released by the Trust in connection with the Montare Sale represented approximately 32% of the fair value of the Royalty Interests at September 1, 2020. As a result of the Montare Sale, the Trust properties consisted of Royalty Interests in 65 Trust Wells as of December 31, 2020.

Proved Reserves. The estimates of net proved oil, natural gas and NGL reserves set forth in the table below are based on reserve reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum engineers (“Netherland Sewell”). 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, 2020, 2019 and 2018 were based on the average price during the 12-month periods ended December 31, 2020, 2019 and 2018, 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 senior engineer is the technical person primarily responsible for overseeing the preparation of the Trust’s reserve estimates on behalf of the Trustee. In order to ensure the reliability of reserves estimates, Avalon’s internal controls observed within the reserve estimation process included:

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.

The Senior Engineer 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.

Netherland Sewell 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 the referenced report, as of December 31, 2020, include the following:

practicing consulting petroleum engineering since 1989 and over 9 years of prior industry experience;

licensed professional engineers in the State of Texas; and

a Bachelor of Science Degree in Civil Engineering.

The qualifications of Netherland Sewell’s technical personnel primarily responsible for overseeing the preparation of the Trust’s reserves estimates included in the referenced reports, as of December 31, 2019, and December 31, 2018, include the following:

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, 2020, NGL constituted approximately 8% 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 Andrews County, Texas, is presented below:

	December 31,
Estimated Proved Reserves(1)	2020(2)		2019		2018
Developed
Oil (MBbls)		794.9		3,918.7		4,567.5
NGL (MBbls)		72.9		411.5		691.8
Natural gas (MMcf)		259.7		1,359.1		2,163.8
Total proved developed (MBoe)(3)		911.1		4,556.8		5,619.9

Undeveloped(4)
Oil (MBbls)		—		—		—
NGL (MBbls)		—		—		—
Natural gas (MMcf)		—		—		—
Total proved undeveloped (MBoe)(3)		—		—		—

Total Proved
Oil (MBbls)		794.9		3,918.7		4,567.5
NGL (MBbls)		72.9		411.5		691.8
Natural gas (MMcf)		259.7		1,359.1		2,163.8
Total proved (MBoe)(3)		911.1		4,556.8		5,619.9

PV-10 (in millions)(5)	$	13.4	$	104.0	$	135.7
Standardized Measure of Discounted Net Cash Flows (in millions)(6)	$	13.4	$	103.8	$	135.5

(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, 2020	$	36.82	$	14.63	$	0.74	$	39.54	$	1.99
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

(2)

Reduction in reserves is due primarily to (i) the shut-in of a number of Trust Wells during the period and (ii) a substantial reduction in the number of Trust Wells as a result of the Montare Sale.

(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)

Royalty Interests conveyed to the Trust by Avalon were in proved properties only.

(5)

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,
	2020		2019		2018

	(in millions)
Standardized Measure of Discounted Net Cash Flows (4)	$	13.4	$	103.8	$	135.5
Present value of future income tax discounted at 10%		0.0		0.2		0.2
PV-10	$	13.4	$	104.0	$	135.7

(6)

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,
	2020 (1)		2019 (2)		2018 (3)
Production Data
Oil (MBbls)		241		414		485
NGL (MBbls)		29		57		72
Natural gas (MMcf)		107		181		227
Combined equivalent volumes (MBoe)(4)		288		501		595
Average daily total volumes(MBoe/d)		1.0		1.4		1.6

Average Prices
Oil (per Bbl)	$	38.10	$	50.77	$	56.96
NGL (per Bbl)	$	14.82	$	20.00	$	24.16
Natural gas (per Mcf)	$	0.68	$	1.22	$	1.91
Total (per Boe)	$	33.68	$	44.66	$	50.08
Average Prices - including impact of post-production expenses
Natural gas (per Mcf)	$	0.37	$	0.95	$	1.71
Total (per Boe)	$	33.56	$	44.56	$	50.00

Expenses (per Boe)
Post-production	$	0.11	$	0.10	$	0.08
Production taxes	$	1.62	$	2.12	$	2.39
Total expenses	$	1.73	$	2.22	$	2.47

(1)

Production volumes and related revenues and expenses for the year ended December 31, 2020 (included in 2020 net revenue distributions to the Trust) represent production from September 1, 2019 to November 30, 2019 and March 1, 2020 to August 31, 2020. Avalon did not make a distribution of revenue to the Trust for the production period from December 1, 2019 to February 29, 2020.

(2)

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.

(3)

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.

(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, 2020 the number of productive wells burdened by the Royalty Interests. Productive wells consist of producing wells and wells capable of producing oil or natural gas in sufficient quantities to justify completion as an oil or natural gas well. 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

—

Drilling Activity

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. As a result, there were no wells drilled or completed during 2020 or 2019, and there were no wells to be drilled or awaiting completion at December 31, 2020 or 2019.

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, 2020 and 2019 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 2020, one customer individually accounted for more than 10% of total revenue attributable to the Royalty Interests. During 2019, 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.

	Sales			% of Revenue
	(in thousands)
2020
Ace Energy Solutions	$	9,188	(1)		94.9	%

2019
Enterprise Crude Oil LLC	$	17,063			81.2	%
ConocoPhillips Company	$	3,951			18.8	%

(1) The reason for the significant decline in sales is due to the decrease in the number of producing wells burdened by Trust Royalty Interests and decrease in prices received.

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:

•

royalties and other burdens, express and implied, under oil and natural gas leases;

•

production payments and similar interests and other burdens created by Avalon’s predecessors in title;

•

a variety of contractual obligations arising under operating agreements, farm-out agreements, production sales contracts and other agreements that may affect the Underlying Properties or their titles;

•

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;

•

pooling, unitization and communitization agreements, declarations and orders;

•

easements, restrictions, rights-of-way and other matters that commonly affect real property;

•

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

•

rights reserved to or vested in the appropriate governmental agency or authority to control or regulate the Underlying Properties.

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 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.

Although the Trump Administration had taken steps aimed at reducing federal regulatory burdens and costs for the oil and gas industry, since taking office in January 2021 the Biden Administration has adopted positions that would eliminate many of the steps taken by the Trump Administration to reduce such burdens and costs. 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”). Following the 2016 presidential election and change in administrations, the EPA convened a reconsideration proceeding that culminated in a 2020 final rule that eliminated the obligation to control methane emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements because they serve to control emissions of other pollutants. However, on January 20, 2021, President Biden issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding those 2020 amendments to the Methane Rule by September 2021. That same order directs the EPA to propose new rules to establish standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, by September 2021. The ultimate fate of the Methane Rule and any related requirements for existing sources is unclear. Nevertheless, regulations promulgated under the CAA may require Avalon to incur development expenses to install and utilize specific equipment, technologies, or work practices to control emissions from its operations.

In addition, in November 2016, the U.S. Department of the Interior Bureau of Land Management (“BLM”) issued final rules to reduce methane emissions from venting, flaring, and leaks during oil and gas operations on federal and tribal lands (the “BLM Methane and Waste Prevention Rule”) that are substantially similar to the EPA’s Methane Rule. However, 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. In September 2018, the BLM published a final rule revising or rescinding certain provisions of the 2016 rule; however, the 2018 rule is currently being challenged in federal court. Although the future implementation of the EPA and BLM rules aimed at controlling GHG emissions from oil and natural gas sources remains uncertain, future federal GHG regulations for the oil and gas industry remain a possibility given the long-term trend towards increasing regulation. Moreover, several states already have adopted rules requiring operators of both new and existing sources to develop and implement a leak detection and repair (“LDAR”) program and to install devices on certain equipment to capture 95 percent of methane emissions. Compliance with these rules could require SandRidge 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.

In addition, a number of state and regional efforts 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. At the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals every five years beginning in 2020. While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements. In November 2019, however, plans were formally announced for the U.S. to withdraw from the Paris Agreement, and the U.S.’s withdrawal from the Paris Agreement took effect on November 4, 2020. On January 20, 2021, President Biden issued an executive order commencing the process to reenter the Paris Agreement, although the emissions pledges in connection with that effort have not yet been updated. The U.S. formally rejoined the Paris Agreement in February 2021. The Trust cannot predict whether re-entry into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements will cause SandRidge to incur material costs.

In a separate executive order issued on January 20, 2021, President Biden asked the heads of all executive departments and agencies to review and take action to address any Federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with or present obstacles to the administration’s stated goals of protecting public health and the environment, and conserving national monuments and refuges. A preliminary list must be provided to the Office of Management and Budget within 30 days of the order. Regulations specifically mentioned for review and possible suspension, revision or rescission include the Methane Rule, and the EPA was ordered to, among other things, propose new regulations to establish comprehensive standards for performance and emission guidelines for methane from existing oil and gas operations by September 2021. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane,” which are “the monetized damages associated with incremental increased in greenhouse gas emissions,” including “changes in net agricultural productivity, human health, property damage from increased flood risk, and the value of ecosystem services.” Various recommendations from the Working Group are due beginning June 1, 2021 and final recommendations no later than January 2022.

The EPA also is charged with establishing National Ambient Air Quality Standards (“NAAQS”), the implementation of which can indirectly impact Avalon’s operations. The CAA directs the EPA to review each NAAQS every five years to ensure that the standards are protective of public health and welfare. This process routinely results in the tightening of those standards, and in October 2015, the EPA lowered the NAAQS for ozone from 75 to 70 parts per billion. In December 2020, the EPA published a final rule that retained without revision the 2015 NAAQS ozone standard. The Biden Administration will have an opportunity to revisit the ozone NAAQS. 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 or federal implementation of the revised NAAQS could result in stricter permitting or regulatory 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, 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.

Future federal GHG regulations for the oil and gas industry remain a possibility given the long-term trend towards increasing regulation and the backing of such action by the Biden Administration, although the form of these regulations remains uncertain. In addition, 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, the United States Army Corp of Engineers (“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 98^th 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 allowed by federal regulations to send wastewater to an off-site private centralized wastewater treatment (“CWT”) facility in most circumstances. CWT facilities can either discharge treated water directly to surface waters or send it to a POTW. In 2018, the EPA concluded a study of the treatment and discharge of oil and gas wastewater that could lead to changes in requirements for discharge of produced water under federal regulations, including more stringent requirements or a prohibition on discharge of produced water from CWT facilities. Any restriction of disposal options for hydraulic fracturing waste and other changes to CWA discharge requirements may result in increased costs. 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 April 21, 2020, EPA and the ACE issued a revised regulation (“2020 rule”) that narrowed the definition from that in the 2015 rule. Litigation has been filed on the 2020 rule, but it is currently effective in all jurisdictions. In January 2021, President Biden issued an Executive Order announcing that the new administration would review the 2020 rule, and the administration has asked that litigation on the 2020 rule be stayed while it considers how to proceed. To the extent that 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 WOTUS. The OPA requires measures to be taken to prevent the accidental discharge of oil into WOTUS 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 EPA 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 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 injection 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

Summary of Risk Factors

The risk factors summarized and detailed below could materially harm production from the Underlying Properties, operating results and/or the Trust’s financial condition, adversely affect proceeds to the Trust and cash distributions to Trust unitholders, and/or cause the price of the Trust units to decline. These are not all of the risks the Trust faces, and other factors not presently known to the Trust or that the Trust currently believes are immaterial may also affect the Trust if they occur. These risks and uncertainties include, but are not limited to, the following:

	·	The Trust was required to dissolve and commence winding up beginning February 26, 2021 pursuant to the terms of the Trust Agreement, which will result in the cancellation of the Trust units. If the Trust units are trading at a price in excess of any final distribution that may be reasonably expected to be made by the Trust following the distribution of the net proceeds from the sale of the Trust’s assets, the trading price of the Trust units is likely to include one or more abrupt decreases in value;

Producing oil, natural gas and NGL is a high risk activity with many uncertainties that could adversely affect future production from the Underlying Properties and result in operational hazards that can cause substantial losses.

The ongoing COVID-19 pandemic and related economic turmoil have affected and could continue to adversely affect proceeds to the Trust and quarterly cash distributions to unitholders.

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.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices.

Actual petroleum reserves attributable to the Underlying Properties and future production may be less than current estimates.

Production of oil, natural gas and NGL from the Underlying Properties could be materially and adversely affected by severe or unseasonable weather.

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 sale of oil, natural gas and NGL by Avalon (as agent of the Trust) and royalty payments to the Trust for distribution by the Trust to unitholders depends in part on Avalon’s access to gathering, transportation and processing facilities.

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 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 value of the Royalty Interests is highly dependent on the performance and financial condition of Avalon.

The Trust has no authority to remove or replace Avalon as operator of the Underlying Properties and the bankruptcy of Avalon could impede the operation of wells.

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.

The Trust is administered by a Trustee who cannot be replaced except at a special meeting of Trust unitholders.

Avalon, as a working interest owner in the Underlying Properties, could have interests that conflict with the interests of the Trust and 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 have limited ability to enforce provisions of the Trust Agreement.

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.

Climate change laws and regulations restricting emissions of green-house gases could result in increased operating costs with respect to the Underlying Properties.

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.

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 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.

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.

Tax gain or loss on the disposition of the Trust units could be more or less than expected.

For a more complete discussion of the material risks facing the Trust, see below.

Risks Related to the Termination of the Trust

The Trust was required to dissolve and commence winding up beginning February 26, 2021 pursuant to the terms of the Trust Agreement, which will result in the cancellation of the Trust units. If the Trust units are trading at a price in excess of any final distribution that may be reasonably expected to be made by the Trust following the distribution of the net proceeds from the sale of the Trust’s assets, the trading price of the Trust units is likely to include one or more abrupt decreases in value.

The Trust Agreement requires the Trust to dissolve and commence winding up of its business and affairs if cash available for distribution for any four consecutive quarters, on a cumulative basis, is less than $5.0 million. Cash available for distribution for the four consecutive quarters ended December 31, 2020, on a cumulative basis, totaled approximately $2.4 million, due in part to Avalon’s inability to make the May 2020 Quarterly Payment to the Trust. Because Avalon’s inability to make the May 2020 Quarterly Payment contributed to the insufficient cumulative cash available for distribution over the four-quarter period, the Trustee and Avalon submitted to an arbitration panel, in accordance with the Trust Agreement, the question of whether the Trust nonetheless remains required to dissolve following the end of that period. On February 25, 2021, the arbitration panel determined that the existence of the unpaid May 2020 Quarterly Payment does not alter the requirement of the Trust to terminate under the provisions of the Trust Agreement. As a result, the Trust was required to dissolve and commence winding up beginning as of the close of business on February 26, 2021. Accordingly, the Trustee is required to sell all of the Trust’s assets, 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, which is expected to include the establishment of cash reserves in such amounts as the Trustee in its discretion deems appropriate for the purpose of making reasonable provision for all claims and obligations of the Trust, including any contingent, conditional or unmatured claims and obligations, in accordance with the Delaware Statutory Trust Act. Such a reserve could reduce or eliminate the amount of, or delay the timing of payment of, sale proceeds that may be distributed to unitholders.

The Trustee expects to complete the sale of the Trust’s assets by the end of the third quarter of 2021 and distribute the net proceeds of the sale (together with any cash reserves in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities of the Trust) to the Trust unitholders on the following quarterly payment date, and the Trust units are expected to be canceled shortly thereafter. Pending the sale or sales of the Royalty Interests, and subject to the effective date and other terms of such sale or sales, the Trust anticipates that it will continue to receive income from the Royalty Interests and will continue to make quarterly distributions to Trust unitholders to the extent there is available cash after payment of Trust expenses and additions to cash reserves. The sale process will involve costs that will reduce the amounts of any distributions to Trust unitholders during the winding up period.

If the Trust units are trading at a price in excess of any final distribution amount that may reasonably be expected to be made by the Trust following the distribution of the net proceeds from the sale of the Trust’s assets, the trading price of the Trust units is likely to include one or more abrupt decreases in value. The market price of the Trust units may be affected by factors other than expectations regarding the possibility of any final distribution amount.

Operating Risks

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:

reductions in oil, natural gas and NGL prices;

equipment malfunctions, failures or accidents;

lack of available gathering facilities;

lack of available capacity on interconnecting transmission pipelines;

lack of adequate electrical infrastructure and water disposal capacity;

unexpected operational events;

pipe or cement failures and casing collapses;

uncontrollable flows of oil, NGL, natural gas, brine, water or drilling fluids;

natural disasters;

environmental hazards, such as oil spills, natural gas and NGL leaks, pipeline or tank ruptures, encountering excessive levels of 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;

high costs, shortages or delivery delays of equipment, labor or other services;

compliance with environmental and other governmental requirements;

adverse weather conditions, such as extreme cold, fires caused by extreme heat or lack of rain and severe storms or tornadoes; and

demand for oil, natural gas and NGL in the location of Trust Wells.

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 will be reduced.

The ongoing COVID-19 pandemic and related economic turmoil have affected and could continue to adversely affect proceeds to the Trust and quarterly cash distributions to unitholders.

The global spread of COVID-19 created significant volatility, uncertainty, and economic disruption during 2020 and continuing through the beginning of 2021. The ongoing COVID-19 pandemic has reached more than 200 countries and has continued to be a rapidly evolving economic and public health situation. The pandemic has resulted in widespread adverse impacts on the global economy, and there is considerable uncertainty regarding the extent to which COVID-19 will continue to spread and mutate. The extent and duration of federal, state and local governmental measures implemented to try to slow the spread of the virus, such as quarantines, shelter-in-place orders and business and government shutdowns are uncertain. State and local authorities have implemented multi-step policies with the goal of re-opening businesses and commerce. However, certain jurisdictions began re-opening only to return to restrictions in the face of increases in new COVID-19 cases. The ultimate impact of COVID-19 on the Trust and Avalon will depend on future developments, which are highly uncertain, difficult to predict and largely outside of the Trust’s control, including, among others, the continued spread, duration and severity of the pandemic outbreak; the occurrence, spread, duration and severity of any subsequent wave or waves of outbreaks; the consequences of governmental and other measures designed to prevent the spread of the virus; the development of effective treatments and vaccines; actions taken by governmental authorities, Avalon’s customers and other third parties; workforce availability; and the timing and extent to which normal economic and operating conditions resume.

The impact of the pandemic, including a resulting reduction in demand for oil and natural gas, coupled with the sharp decline in commodity prices following the announcement of price reductions and production increases in March 2020 by members of OPEC, has led to significant global economic contraction generally and in the oil and gas industry in particular, which experienced a significant downturn during 2020 and into 2021. Although OPEC and its allies have since agreed to specified production cuts, crude oil prices have remained depressed as a result of the decrease in crude oil demand due to COVID-19. Oil and natural gas prices are expected to continue to be volatile as a result of near-term production increases (as prices have recovered from all-time lows) and the ongoing COVID-19 pandemic and as changes in oil and natural gas inventories, industry demand, and national and economic performance are reported. The Trust cannot predict when prices will improve and stabilize nor the full impact that COVID-19 or the significant disruption and volatility currently being experienced in the oil and natural gas markets will have (i) on Avalon’s business, financial condition and results of operations or (ii) on royalty payments received by the Trust and the Trust’s reserves and quarterly cash distributions to Trust unitholders due to numerous uncertainties.

Continued low oil and natural gas prices may ultimately reduce the amount of oil and natural gas that is economically viable to produce from the Underlying Properties. As a result, Avalon could determine during periods of low commodity prices to shut-in or curtail production from Trust Wells, or even plug and abandon marginal Trust Wells that otherwise may have been allowed to continue to produce for a longer period under conditions of higher prices. Specifically, Avalon may abandon any well or property if it reasonably believes that the well or property can no longer produce oil or natural gas in commercially paying quantities, which could result in termination of the portion of the Royalty Interest relating to the abandoned well, and Avalon has no obligation to drill a replacement well. If commodity prices for crude oil and natural gas remain at reduced levels, cash distributions to Trust unitholders will be substantially lower than historical distributions, and in certain periods there may be no distribution to Trust unitholders.

To the extent COVID-19 adversely affects production from the Underlying Properties or Avalon’s business, results of operations and financial condition, it may also have the effect of heightening many of the other risks described in this Form 10-K.

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:

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;

the price and quantity of foreign imports;

U.S. and worldwide political and economic conditions;

the occurrence or threat of epidemic or pandemic diseases, including the recent outbreak of COVID-19 and its mutant variants, or any government response to such occurrence or threat;

weather conditions and seasonal trends;

future prices of oil, natural gas and NGL, alternative fuels and other commodities;

technological advances affecting energy consumption and energy supply;

the proximity, capacity, cost and availability of pipeline infrastructure, treating, transportation and refining capacity;

natural disasters and other extraordinary events;

domestic and foreign governmental regulations and taxation;

energy conservation and environmental measures; and

the price and availability of alternative fuels.

These factors and the volatility of energy markets, which is expected to continue, make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty and could result in additional declines from current levels. For crude oil, from January 2019 through December 2020, the highest closing spot price for West Texas Intermediate (WTI) was $66.24 per Bbl and the lowest was negative $36.98 per Bbl. For natural gas, from January 2019 through December 2020, the highest closing Henry Hub natural gas spot price was $4.25 per MMBtu and the lowest was $1.33 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 and natural gas prices experienced substantial fluctuations during 2019 and 2020, ending 2020 at $48.35/Bbl (the spot price for WTI crude oil) and $2.09/Mcf, as compared to $61.14/Bbl and $2.36/Mcf at December 31, 2019.

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.

The ability or willingness of OPEC and other oil exporting nations to set and maintain production levels has a significant impact on oil and natural gas commodity prices, which could reduce the amount of cash available for distribution to Trust unitholders.

OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, those negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed upon oil production cuts would expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices, which reached a closing WTI price low of negative $36.98 per Bbl of crude oil in April 2020. OPEC members and other oil exporting nations might not agree to future production cuts or other actions to support and stabilize oil prices. Moreover, they might not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could adversely affect the financial condition and economic performance of the operators of the underlying properties and may reduce the net proceeds to which the Trust is entitled, which could materially reduce or completely eliminate the amount of cash available for distribution to Trust unitholders.

Actual petroleum reserves attributable to the Royalty Interests 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 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 from the Underlying Properties and related revenues from the sale of such production 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 with respect to the Trust Wells 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:

historical production from the Underlying Properties compared with production rates from other producing areas in the Permian Basin;

oil, natural gas and NGL prices, production levels, Btu content, production expenses, transportation costs, severance and excise taxes and capital expenditures; and

the assumed effect of governmental regulation.

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 any particular reserve report with respect to the Royalty Interests.

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:

changes in oil viscosity as a result of extremely cold weather conditions;

evacuation of personnel and curtailment of operations;

weather-related damage to facilities, resulting in suspension of operations;

inability to deliver materials to worksites; and

weather-related damage to pipelines and other transportation facilities.

Recent record-setting low temperatures in the Permian Basin resulted in significant reductions in production during February 2021. Further 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.

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 Trust Well 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. 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.

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 from 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 Trust Well is damaged, Avalon has no obligation to drill a replacement well or make the Trust whole for the loss of production from such well. 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.

Financial Risks

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. 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 with respect to Trust Wells 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. The Trust Agreement also specifically excludes the Trust from acquiring other oil and natural gas properties or royalty interests to replace the Underlying Properties (depleting assets) 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:

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);

the Trust’s share of applicable taxes, including property taxes and taxes on the production of oil, natural gas and NGL;

the Trust’s liability for Texas franchise tax; and

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 and other material operations of the Trust.

In addition, the amount of funds available for distribution to Trust unitholders may be reduced by the amount of any cash reserves established 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 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 $3,275,000. In 2019 and 2020, the Trustee withheld $760,000 and $570,000, respectively, from the funds otherwise available for distribution to Trust unitholders. In light of the fact that there would be no distribution from production for the three-month period ended December 31, 2020 (with respect to production attributable to the Trust’s Royalty Interests from September 1, 2020 to November 30, 2020), the Trustee elected to withhold approximately $884,000, the remaining amount needed to reach its targeted cash reserve, in connection with the distribution made in February 2021 from funds received by the Trust as fair value for the portion of the Trust’s Royalty Interests required to be released in connection with the Montare Sale. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to Trust unitholders.

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 since March 31, 2015 has been 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 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 Trust Wells. The Conveyances provide that Avalon is obligated to market, or cause to be marketed, the oil, natural gas and NGL produced by such Trust Wells (to the extent such Trust 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. Avalon has notified the Trustee that current reductions in production of crude oil and the current low prices for crude oil have adversely impacted Avalon’s financial condition. This negative impact could affect Avalon’s ability to operate the Trust Wells and provide services to the Trust. In addition, Avalon has informed the Trustee that Avalon’s independent public accounting firm included a going concern qualification in its audit report on Avalon’s financial statements for the fiscal years ended December 31, 2019 and 2020.

In April 2020, Avalon informed the Trustee that Avalon had been using its commercially reasonable efforts to preserve the oil and gas leases on which the Trust Wells are located so that when crude oil prices returned to a profitable level, the Trust would continue to hold its Royalty Interests, and Trust unitholders might have the opportunity to receive future quarterly distributions. Avalon also informed the Trustee that Avalon believed that continuing production from the Trust Wells required to preserve such leases was preferable to stopping production, as the failure to continue production would result in a termination of Avalon’s working interest in such Trust Wells and, therefore, the Royalty Interests, which would have a material adverse effect on the Trust’s financial condition. Avalon reported to the Trustee that Avalon therefore used revenues it received during the production period from December 1, 2019 to February 29, 2020 to pay the operating expenses necessary to maintain production from the Trust Wells and to pay oil and gas lessor royalties, as the proceeds attributable to Avalon’s net revenue interest in the Underlying Properties was insufficient to cover all such costs. Avalon had anticipated that revenues from production during the quarterly production period from March 1, 2020 to May 31, 2020 would be sufficient to fund the May 2020 Quarterly Payment to the Trust; however, revenues from production during that quarterly production period were insufficient to generate the cash needed to make the May 2020 Quarterly Payment to the Trust due to the sharp drop in crude oil prices during the first quarter of 2020. Consequently, the Trustee was unable to make any quarterly distribution to unitholders at the end of May 2020. As of December 31, 2020, Avalon had not paid any of the May 2020 Quarterly Payment, or any interest accrued thereon through such date, to the Trust. Avalon may pay to the Trust the outstanding amount of the May 2020 Quarterly Payment in installments over an extended period of time, and may be unable to pay to the Trust the entire outstanding amount of the May 2020 Quarterly Payment.

In connection with the Sale Transaction, Avalon obtained a revolving line of credit from WaFed pursuant to the terms of the WaFed Loan. Since April 2020, Avalon has been in discussions with WaFed regarding forbearance of certain breached financial covenants and an extension of the WaFed Loan. WaFed and Montare have entered into a Participation Agreement with respect to the WaFed Loan whereby Montare purchased an undivided participation interest in the WaFed Loan and Montare has the right to purchase the WaFed Loan in the event Avalon does not meet the conditions of the amended WaFed Loan. Meanwhile, Avalon and WaFed have amended the WaFed Loan to require Avalon to pay off the WaFed Loan by April 15, 2021. If Avalon is unable to repay the WaFed Loan or amend the WaFed Loan to extend the repayment date, Avalon could be forced to sell its interests in the Underlying Properties and WaFed may be required to find a replacement operator for the Underlying Properties, which could have an adverse effect on the value of the Royalty Interests or result in decreased distributions to Trust Unitholders or both.

The bankruptcy of Avalon could impede the operation of Trust Wells.

The value of the Royalty Interests and the Trust’s ultimate cash available for distribution is highly dependent on the financial condition of Avalon as the operator of the Trust Wells. The Trustee does not have any authority to remove or replace Avalon as the operator of the Trust 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 Avalon’s 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 Avalon.

Avalon is not a reporting company and is not required to file periodic reports with the SEC pursuant to the Exchange Act. Therefore, Trust unitholders do not have access to financial information about Avalon. Avalon has informed the Trustee that Avalon’s independent public accounting firm included a going concern qualification in its audit report on Avalon’s financial statements for the fiscal year ended December 31, 2020. 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.

Risks Related to the Structure of the Trust

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 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.

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:

Avalon’s interests may conflict with those of the Trust and the Trust unitholders in situations involving the maintenance, operation or abandonment of particular oil and gas wells located on the Underlying Properties. Additionally, Avalon may, consistent with its obligation to act in good faith and in accordance with the Reasonably Prudent Operator Standard, shut in a well that is uneconomic or not generating revenues from production in excess of its operating costs. Avalon may make decisions with respect to expenditures based on the economic viability of a particular well, which could cause oil, natural gas and NGL production to decline at a faster rate and thereby result in lower royalty payments to the Trust by Avalon for distribution by the Trust to unitholders in the future.

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.

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.

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.

Avalon can sell its Trust units regardless of the effect 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.

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. The Trust has not requested and Avalon has not made any such loan to the Trust as of December 31, 2020. Avalon has informed the Trustee that given Avalon’s present financial condition, it does not have the financial resources to make a loan to the Trust if so requested.

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 Trust Wells. 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.

Risks Related to Ownership of the Trust Units

The Trust units have been delisted from the New York Stock Exchange and are traded on the OTC market. It will likely be more difficult for unitholders to sell the Trust units or to obtain accurate quotations of the Trust units.

The Trust units ceased trading on The New York Stock Exchange (“NYSE”) on September 8, 2020 and transitioned to OTC Pink Market, which is operated by OTC Markets Group Inc. (“OTC Pink”), effective with the opening of trading on September 9, 2020 under the trading symbol “PERS”. A trading market for the Trust units might not continue to exist on the OTC Pink. Moreover, current trading levels might not be sustained or could diminish. Securities traded on the over-the-counter markets are typically less liquid than stocks that trade on the NYSE. Trading on the OTC Pink may negatively affect the trading price and liquidity of the Trust units and could result in larger spreads in the bid and ask prices for Trust units. Trust unitholders may find it difficult to resell their Trust units due to the delisting.

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 prohibits 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. The Trust Agreement also provides (a) that Avalon (as successors to SandRidge) may exercise its rights and discharge its 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 personal 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 16, 2021, 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, WaFed. In the event Avalon could obtain WaFed’s permission 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.

Legal, Environmental and Regulatory Risks

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, while the physical effects of climate change could disrupt Avalon’s production and cause Avalon to incur significant costs in preparing for or responding to those effects.

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 culminated in a 2020 final rule that eliminated the obligation to control methane emissions under the NSPS, while maintaining the rule’s substantive emissions control requirements because they serve to control emissions of other, non-methane pollutants. However, on January 20, 2021, President Biden issued an executive order calling on the EPA to, among other things, consider a proposed rule suspending, revising or rescinding those 2020 amendments to the Methane Rule by September 2021. That same order directs the EPA to propose new rules to establish standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, by September 2021. The ultimate fate of the Methane Rule and any related requirements for existing sources is unclear. Nevertheless, regulations promulgated under the CAA may require 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. At the international level, the U.S. joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France, which resulted in an agreement intended to nationally determine their contributions and set greenhouse gas emission reduction goals every five years beginning in 2020. While the Agreement did not impose direct requirements on emitters, national plans to meet its pledge could have resulted in new regulatory requirements. The U.S. withdrew from the Paris Agreement effective on November 4, 2020, but rejoined the Paris Agreement in February 2021. The Trust cannot predict whether re-entry into the Paris Agreement or pledges made in connection therewith will result in new regulatory requirements or whether such requirements will cause Avalon to incur material costs.

In a separate executive order issued on January 20, 2021, President Biden asked the heads of all executive departments and agencies to review and take action to address any Federal regulations, orders, guidance documents, policies and any similar agency actions promulgated during the prior administration that may be inconsistent with or present obstacles to the administration’s stated goals of protecting public health and the environment, and conserving national monuments and refuges. Regulations specifically mentioned for review and possible suspension, revision or rescission include the Methane Rule, and the EPA was ordered to, among other things, propose new regulations to establish comprehensive standards for performance and emission guidelines for methane from existing oil and gas operations by September 2021. The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases, which is called on to, among other things, capture the full costs of greenhouse gas emissions, including the “social cost of carbon,” “social cost of nitrous oxide” and “social cost of methane,” which are “the monetized damages associated with incremental increased in greenhouse gas emissions,” including “changes in net agricultural productivity, human health, property damage from increased flood risk, and the value of ecosystem services.”

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.

Although it is not currently possible to predict how these executive orders or any proposed or future state or federal greenhouse gas legislation or regulation will impact Avalon’s business, any regulation of greenhouse gas emissions that may be imposed in areas in which Avalon conducts business could result in increased compliance costs or additional operating restrictions or reduced demand for Avalon’s production.

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. Climate changes that have significant physical effects could also increase or decrease energy needs, depending on the duration and magnitude of those effects. 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.

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.

Cybersecurity Risks

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 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 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 of production attributable to the Royalty Interests 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 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 foreign governments, organized crime, hackers and third parties to whom certain functions are outsourced, or may originate internally. 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 by the Trustee to prevent and detect such attacks, it is possible that a cyber incident will not be discovered for some time after it occurs, which could increase exposure to these consequences.

Tax Risks Related to the Trust Units

The Trust’s tax treatment depends on its status as a partnership for U.S. federal income tax purposes. If the 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 has had 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 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.

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 the Trust 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.

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.

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 a 30% rate 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 a 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 or another exception is available. Pursuant to final Treasury Regulations issued on October 7, 2020, this new withholding obligation will become applicable to transfers of units in publicly traded partnerships such as the Trust (which is classified as a partnership for federal and state income tax purposes) occurring on or after January 1, 2022.

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 10 to the financial statements included in Item 8 of this report.

Item 3. Legal Proceedings

None.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

The Trust units commenced trading on the New York Stock Exchange (“NYSE”) on August 11, 2011 under the symbol “PER” and were delisted on the NYSE effective October 9, 2020. The Trust units transitioned to the OTC Pink Market, operated by OTC Markets Group, effective with the opening of trading on September 9, 2020 under the trading symbol “PERS.”

The following table shows the high and low sales/bid prices, as applicable, per Trust unit as reported on the NYSE and the OTC Pink Market, as applicable, for the periods indicated. Quotations on the OTC Pink Market reflect bid and ask quotations, may reflect inter-dealer prices, without retail markup, markdown or commission, and may not represent actual transactions.

	High		Low
Calendar Quarter 2020
First Quarter	$	1.14	$	0.25
Second Quarter	$	0.75	$	0.41
Third Quarter	$	0.85	$	0.30
Fourth Quarter	$	0.55	$	0.34

Calendar Quarter 2019
First Quarter	$	2.50	$	0.85
Second Quarter	$	2.55	$	1.45
Third Quarter	$	1.94	$	1.52
Fourth Quarter	$	1.70	$	0.80

On March 16, 2021, there were ten record unitholders of the Trust units as reported by American Stock Transfer & Trust Company, LLC. CEDE & Co. holds 39,306,105 Trust units in “street name”.

Distributions

Equity Compensation Plans

The Trust does not have any employees and, therefore, does not maintain any equity compensation plans.

Recent Sales of Unregistered Securities

None.

Purchases of Securities

There were no purchases of Trust units by the Trust or any affiliated purchaser during the fourth quarter of 2020.

Item 6. Selected Financial Data

As a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K, the Trust is not required to provide information required by this Item.

Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations

Introduction

The following discussion and analysis is intended to help the reader understand the Trust’s business, financial condition, results of operations, liquidity and capital resources. This discussion and analysis should be read in conjunction with other sections of this report, including: “Business” in Item 1 and “Financial Statements and Supplementary Data” in Item 8. The discussion and analysis relate to the following subjects:

	•	Trust Termination and Overview:

	•	Recent Developments;

•

Results of Trust Operations;

•

Liquidity and Capital Resources;

•

Critical Accounting Policies and Estimates; and

•

Off-Balance Sheet Arrangements

Trust Termination and Overview

The following is a brief overview of certain matters discussed more thoroughly elsewhere in this report.

The Trust Agreement requires the Trust to dissolve and commence winding up of its business and affairs if cash available for distribution for any four consecutive quarters, on a cumulative basis, is less than $5.0 million. Pursuant to the Trust Agreement, cash that the Trust receives as proceeds from sales of assets is not included in the calculation of cash available for distribution. As cash available for distribution for the four consecutive quarters ended December 31, 2020, on a cumulative basis, totaled approximately $2.4 million, due in part to Avalon’s inability to make the May 2020 Quarterly Payment to the Trust (as discussed below under “—The May 2020 Quarterly Payment”). Because Avalon’s inability to make the May 2020 Quarterly Payment contributed to the insufficient cumulative cash available for distribution over the four-quarter period, the Trustee and Avalon submitted to an arbitration panel, in accordance with the Trust Agreement, the question of whether the Trust nonetheless remains required to dissolve following the end of that period. On February 25, 2021, the arbitration panel determined that the existence of the unpaid May 2020 Quarterly Payment does not alter the requirement of the Trust to terminate under the provisions of the Trust Agreement. As a result, the Trust was required to dissolve and commence winding up beginning as of the close of business on February 26, 2021.

Accordingly, the Trustee is required to sell all of the Royalty Interests, either by private sale or public auction, and distribute the net proceeds of such sale to the Trust unitholders after payment, or reasonable provision for payment, of all Trust liabilities, which is expected to include the establishment of cash reserves in such amounts as the Trustee in its discretion deems appropriate for the purpose of making reasonable provision for all claims and obligations of the Trust, including any contingent, conditional or unmatured claims and obligations, in accordance with the Delaware Statutory Trust Act. The sale process will involve costs that will reduce the amount of any distributions to unitholders during the winding up period. As required by the Trust Agreement, the Trustee has engaged a third-party advisor to assist with the marketing and sale of the Royalty Interests. As provided in the Trust Agreement, Avalon has a right of first refusal with respect to any sale of the Royalty Interests to a third party. The Trustee expects to complete the sale of the Trust’s assets by the end of the third quarter of 2021 and distribute the net proceeds of such sale (together with any cash reserves in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities of the Trust) to the Trust unitholders on the following quarterly payment date, and the Trust units are expected to be canceled shortly thereafter. Pending the sale or sales of the Royalty Interests, and subject to the effective date and other terms of such sale or sales, the Trust anticipates that it will continue to receive income from the royalty interests and will continue to make quarterly distributions to unitholders to the extent there is available cash after payment of Trust expenses and additions to cash reserves. The Trust will remain in existence until the filing of a certificate of cancellation with the Secretary of State of the State of Delaware following the completion of the winding up process.

The value of the petroleum reserves attributable to the Trust’s Royalty Interests and the amount of cash available for distribution to Trust unitholders are each highly dependent upon the prices realized from the sale of oil, natural gas and NGL. The markets for these commodities are volatile and experienced significant fluctuations during 2019 and have declined sharply in 2020 in response to the economic effects of the dispute over production levels between Russia and the members of the Organization of Petroleum Exporting Countries and the global outbreak of the novel form of coronavirus known as COVID-19. These actions led to an immediate and steep decrease in oil prices, which reached a closing WTI price low of negative $36.98 per barrel of crude oil in April 2020. The spot price for WTI crude oil has decreased from $61.17 per barrel on January 2, 2020 to $48.35 per barrel on December 31, 2020. A buildup in inventories, lower global demand, political unrest, or other factors, such as the economic effects of the COVID-19 pandemic, could cause prices for U.S. oil, natural gas and NGL to fluctuate significantly in the future. As a result, prices for oil, natural gas and NGL might not be maintained at a constant level for any significant period of time.

Results of Trust Operations

Results of the Trust for the Years Ended December 31, 2020 and 2019

The primary factors affecting the Trust’s revenues and costs are the quantity of oil, natural gas and NGL production attributable to the Royalty Interests and the prices received for such production. Royalty income, post-production expenses and certain taxes are recorded on a cash basis when the Trust receives net revenue distributions from Avalon. Information regarding the Trust’s revenues, expenses, production and pricing for the years ended December 31, 2020 and 2019 is presented below.

	Year Ended December 31,
	2020 (1)			2019 (2)
Production data
Oil (MBbls)		241			414
NGL (MBbls)		29			57
Natural gas (MMcf)		107			181
Combined equivalent volumes (MBoe)(3)		288			501
Average daily total volumes (MBoe/d)		1.0			1.4
Well data
Initial and Trust Development Wells producing - average		863			1,035
Revenues (in thousands)
Royalty income	$	9,704		$	22,442
Proceeds from sale of Trust assets		4,874			—
Total revenue	$	14,578		$	22,442
Expenses (in thousands)
Post-production expenses	$	33		$	50
Property taxes		2,979			—
Production taxes		465			1,061
Franchise taxes		36			47
Trust administrative expenses		1,985			1,734
Cash reserves (used) withheld for current Trust expenses, net of amounts withheld (used)		(2,391	)		2,261
Total expenses	$	3,107		$	5,153
Less proceeds from sale of Trust assets		4,874			—
Distributable income available to unitholders	$	6,597		$	17,289

Average prices
Oil (per Bbl)	$	38.10		$	50.77
NGL (per Bbl)	$	14.82		$	20.00
Natural gas (per Mcf)	$	0.68		$	1.22
Total (per Boe)	$	33.68		$	44.66
Average prices - including impact of post-production expenses
Natural gas (per Mcf)	$	0.37		$	0.95
Total (per Boe)	$	33.56		$	44.56
Expenses (per Boe)
Post-production	$	0.11		$	0.10
Production taxes	$	1.62		$	2.12

(1)

Production volumes and related revenues and expenses for the year ended December 31, 2020 (included in 2020 royalty payments to the Trust) represent oil, natural gas and NGL production from September 1, 2019 to November 30, 2019 and March 1, 2020 to August 31, 2020. Avalon did not make a royalty payment to the Trust for the production period from December 1, 2019 to February 29, 2020.

(2)

Production volumes and related revenues and expenses for the year ended December 31, 2019 (included in 2019 royalty payments to the Trust) represent oil, natural gas and NGL production from September 1, 2018 to August 31, 2019.

(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.

Comparison of Results of the Trust for the Years Ended December 31, 2020 and 2019

Revenues

Royalty Income. Royalty income is a function of production volumes attributable to the Royalty Interests sold and associated prices received by Avalon. Royalty income received during the year ended December 31, 2020 totaled $9.7 million compared to $22.4 million received during the year ended December 31, 2019. The decrease is partially the result of Avalon’s failure to pay proceeds owed to the Trust for the production period from December 1, 2019 to February 29, 2020 in the amount of approximately $4.7 million. Of the remaining portion of the decrease in royalty income, approximately $3.3 million was attributable to a decrease in prices received from the sale of oil, gas and NGL attributable to the Royalty Interests and approximately $4.7 million was attributable to a decrease in total volumes produced from wells burdened by the Royalty Interests.

Expenses

Post-Production Expenses. The Trust bears post-production expenses related to production attributable to the Royalty Interests. Post-production expenses generally consist of costs incurred to gather, store, compress, transport, process, treat, dehydrate and market, as applicable, the oil, natural gas and NGL produced from wells burdened by and attributable to the Royalty Interests. Post-production expenses for the year ended December 31, 2020 decreased to approximately $33,000 from approximately $50,000 for the year ended December 31, 2019 primarily as a result of a decrease in gas production volumes.

Property Taxes. Property taxes paid during the year ended December 31, 2020 were approximately $3.0 million, which related to 2020 and 2019 property taxes. No property tax payments were made during 2019, as approximately $1.7 million in 2019 property taxes were paid in January 2020.

Production Taxes. Production taxes are calculated as a percentage of oil, natural gas and NGL revenues, excluding the net amount of any applicable tax credits. Production taxes for the year ended December 31, 2020 totaled $0.5 million, or $1.62 per Boe, and were approximately 4.8% of royalty income. Production taxes for the year ended December 31, 2019 totaled $1.1 million, or $2.12 per Boe, and were approximately 4.7% of royalty income.

Texas Franchise Tax. The Trust paid its Texas franchise tax for the year ended December 31, 2019 of approximately $36,000, or approximately 0.2% of 2019 royalty income, during the year ended December 31, 2020. The Trust paid its Texas franchise tax for the year ended December 31, 2018 of approximately $47,000, or approximately 0.2% of 2018 royalty income, during the year ended December 31, 2019. The Trust’s estimated Texas franchise tax for the year ended December 31, 2020 of approximately 0.2% of 2020 royalty income, is expected to be paid during the year ending December 31, 2021.

Distributable Income

Distributable income for the year ended December 31, 2020 was $6.6 million, which included a net reduction of approximately $2.4 million to the cash reserve for the payment of future Trust expenses reflecting approximately $5.0 million used to pay Trust expenses during the period partially offset by approximately $2.6 million withheld in aggregate from 2020 cash distributions to Trust unitholders. Distributable income for the year ended December 31, 2019 was $17.3 million, which included a net addition of approximately $2.3 million to the cash reserve for the payment of future Trust expenses reflecting approximately $4.0 million withheld in aggregate from 2019 cash distributions to Trust unitholders partially offset by approximately $1.7 million used to pay Trust expenses during the period.

Liquidity and Capital Resources

The Trust has no source of liquidity or capital resources other than cash flow generated from the Royalty Interests and borrowings as needed to fund administrative expenses, including any amounts borrowed from Avalon, under the loan commitment described in Note 6 to the financial statements contained in Item 8 of this report, or from the Trustee. The Trust’s primary uses of cash are distributions to Trust unitholders, payment of Trust administrative expenses, including any reserves established by the Trustee for future liabilities, payment of applicable taxes, and payment of expense reimbursements to Avalon for out-of-pocket expenses incurred on behalf of the Trust. The Trust is not obligated to pay any operating expenses or capital costs related to the operation of the wells.

Administrative expenses include payments to the Trustee and the Delaware Trustee, as well as a quarterly fee of $75,000 to Avalon pursuant to the terms of the Administrative Services Agreement. Each quarter, the Trustee determines the amount of funds available for distribution. Available funds are the excess cash, if any, received by the Trust from the sale of production attributable to the Royalty Interests that quarter, over the Trust’s expenses for the quarter. 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 (pursuant to the terms set forth in the Trust Agreement), to pay such expenses. The Trustee has not loaned and does not intend to lend funds to the Trust. 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, no further distributions will be made to unitholders (except in respect of any previously determined quarterly cash distribution amount) until such loan is repaid in full, with interest, unless Avalon consents to any further distributions. Any such loan will be on an unsecured basis, and the terms of such loan will be substantially the same as that which would be obtained in an arm’s length transaction between Avalon and an unaffiliated third party.

Commencing with the distribution to Trust unitholders paid in the first quarter of 2019, the Trustee has withheld the greater of $190,000 or 3.5% of the funds otherwise available for distribution to Trust unitholders each quarter to gradually increase cash reserves for the payment of future known, anticipated or contingent expenses or liabilities by a total of approximately $3,275,000. In 2019 and 2020, the Trustee withheld $760,000 and $570,000, respectively, from the funds otherwise available for distribution. In light of the fact that there would be no distribution from production for the three-month period ended December 31, 2020 (with respect to production attributable to the Trust’s Royalty Interest from September 1, 2020 to November 30, 2020), the Trustee withheld approximately $884,000, the remaining amount needed to reach its targeted cash reserve, in connection with the cash distribution made in February 2021 from funds received by the Trust as fair value for the portion of the Trust’s Royalty Interests required to be released in connection with the Montare Sale. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to Trust unitholders.

Following the closing of the Sale Transaction, the Trust is highly dependent on Avalon for multiple services, including the operation of the wells burdened by the Royalty Interests, remittance of net proceeds to the Trust from the sale of hydrocarbon production attributable to the Royalty Interests, administrative services such as accounting, tax preparation, bookkeeping and reporting 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 Underlying 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. If the reduced demand for crude oil in the global market resulting from the economic effects of the coronavirus pandemic and the dramatic reduction from mid-February to late April 2020 in the benchmark price of crude oil, which continued to fluctuate through 2020, persist for the near term or longer, such factors are likely to continue 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.

Trust Distributions to Unitholders. During the years ended December 31, 2020 and 2019, the Trust’s distributions to its unitholders were as follows:

Covered Production
Period

Date Declared

Date Paid

Total
Distribution Paid

(in millions)

Calendar Quarter 2020

First Quarter

September 1, 2019 - November 30, 2019

January 23, 2020

February 22, 2020

4.2

Second Quarter (1)

December 1, 2019 - February 29, 2020

April 23, 2020

N/A

—

Third Quarter

March 1, 2020 -
May 31, 2020

July 23, 2020

August 31, 2020

0.6

Fourth Quarter

June 1, 2020 - August 31, 2020

October 22, 2020

November 25, 2020

1.7

Calendar Quarter 2019

First Quarter

September 1, 2018 - November 30, 2018

January 24, 2019

February 22, 2019

5.0

Second Quarter

December 1, 2018 - February 28, 2019

April 25, 2019

May 24, 2019

3.7

Third Quarter

March 1, 2019 -
May 31, 2019

July 24, 2019

August 23, 2019

4.7

Fourth Quarter

June 1, 2019 - August 31, 2019

October 24, 2019

November 24, 2019

3.8

(1) Avalon did not make a distribution of revenue to the Trust for the production period from December 1, 2019 to February 29, 2020.

On February 28, 2021, the Trust paid a cash distribution of $0.075 per Trust unit reflecting the fair value to the Trust, less cash reserves withheld by the Trustee, received by the Trust for the portion of the Trust’s Royalty Interests required to be released in connection with the Montare Sale. There was no distribution paid for the three-month period ended December 31, 2020, which primarily related to production attributable to the Trust’s royalty interests from September 1, 2020 to November 30, 2020, as costs, charges and expenses attributable to the Underlying Properties were more than the revenue received from the sale of oil, natural gas and other hydrocarbons produced from such properties, as reported by Avalon.

Continued relatively 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. As the Trust cannot acquire or cause additional wells to be drilled on its behalf, the production from the Underlying Properties attributable to the Royalty Interests is expected to decline each quarter during the remainder of the Trust’s life.

Contractual Obligations. Pursuant to the terms of the Administrative Services Agreement, the Trust is obligated to pay Avalon an annual administrative services fee of $300,000 ($75,000 payable quarterly in arrears) for accounting, tax preparation, bookkeeping, and informational services to be performed on behalf of the Trust for the remaining life of the Trust. Pursuant to the Trust Agreement, the Trust pays the Trustee an annual administrative fee, which until April 1, 2017 was $150,000. The annual fee can be adjusted for inflation by no more than 3% in any year through 2030. The annual administrative fee, which was adjusted for inflation in July 2020, currently is approximately $163,000. In addition, under the Trust Agreement the Trust is obligated to pay the Delaware Trustee an annual fee of $2,400 throughout the life of the Trust.

Critical Accounting Policies and Estimates

The financial statements of the Trust are significantly affected by its basis of accounting and estimates related to the Royalty Interests and proved reserves, as summarized below.

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 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 impairment thereto is charged directly to trust corpus. Distributions to Trust unitholders are recorded when declared. Because the Trust’s financial statements are prepared on a modified cash basis, most accounting pronouncements are not applicable to the Trust’s financial statements.

Proved Reserves. The proved oil, natural gas and NGL reserves attributable to the Royalty Interests are estimated by independent petroleum engineers. Estimates of proved reserves are based on the quantities of oil, natural gas and NGL that geological and engineering data demonstrate, with reasonable certainty, to be recoverable in future years from known reservoirs under existing economic and operating conditions. However, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, production volumes, rates of production and timing of development expenditures, including many factors beyond the Trust’s control. Estimating reserves is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. In addition, as a result of volatility of changing market conditions, commodity prices will vary from period to period, causing estimates of proved reserves to vary, as well as causing estimates of future net revenues to vary. Estimates of proved reserves are key components of the Trust’s most significant financial estimates as discussed further below.

Amortization of Investment in Royalty Interests. 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. The rate used to record amortization is dependent upon the estimate of total proved reserves attributable to the Royalty Interests, which incorporates various assumptions and future projections. If the estimates of total proved reserves decline significantly, the rate at which the Trust records amortization would increase, reducing trust corpus. Such a decline in reserves may result from lower commodity prices, which may make it uneconomic for Avalon to produce from the Underlying Properties, or from other factors, including changes to estimates for other reasons. Changes in reserve quantity estimates are dependent on future economic and operational conditions and cannot be predicted.

Impairment of Investment in Royalty Interests. The investment in the Royalty Interests is assessed to determine whether net capitalized cost is impaired whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. Potential impairments of the investment in the Royalty Interests are determined by comparing the net capitalized costs of investment in the Royalty Interests to undiscounted future net revenues attributable to the Trust’s interest in the proved oil, natural gas and NGL reserves attributable to the Royalty Interests. The Trust provides a write-down to the extent that the net capitalized costs exceed the fair value of the Royalty Interests, which is determined using either a market-based or income-based approach, depending on which is deemed more relevant in the circumstances. The income-based approach uses future cash flows of the oil, natural gas and NGL reserves attributable to the Royalty Interests, discounted at a relevant market participant discount rate. Different pricing assumptions or discount rates could result in a different calculated impairment. During the year ended December 31, 2020, due to the decline in oil and gas prices, the Trust recorded impairments in the carrying value of the Investment in Royalty Interests in aggregate of $83.5 million. The impairments resulted in non-cash charges to trust corpus and did not affect the Trust’s distributable income. No impairments were recorded in 2019. Material write-downs in subsequent periods may occur if commodity prices decline significantly on a sustained basis.

Refer to Note 3 to the financial statements included in Item 8 of this report for the Trust’s significant accounting policies.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk

As a “smaller reporting company” as defined in Item 10(f)(1) of Regulation S-K, the Trust is not required to provide information required by this Item.

Item 8. Financial Statements and Supplementary Data

The Trust’s financial statements required by this item are included in this report beginning on page F-1.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures.

The Trustee conducted an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15(a) and 15d-15(a) as of the end of the period covered by this report. Based on this evaluation, Sarah Newell, as Trust Officer, has concluded that the disclosure controls and procedures of the Trust are effective as of December 31, 2020 to provide reasonable assurance that the information required to be disclosed by the Trust in its reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and such information is accumulated and communicated, as appropriate to allow timely decisions regarding required disclosure. In its evaluation of disclosure controls and procedures, the Trustee has relied, to the extent considered reasonable, on information provided by Avalon with respect to the periods covered by this report.

Due to the nature of the Trust as a passive entity and in light of the contractual arrangements pursuant to which the Trust was created, including the provisions of (i) the Trust Agreement, (ii) the Administrative Services Agreement, and (iii) the Conveyances granting the Royalty Interests, the Trustee’s disclosure controls and procedures related to the Trust necessarily rely on (A) information provided by Avalon (as successor to SandRidge), including information relating to results of operations, the costs and revenues attributable to the Royalty Interests and other operating and historical data, plans for future operating expenditures, reserve information, information relating to projected production, and other information relating to the status and results of operations of the wells burdened by the Royalty Interests, and (B) conclusions and reports regarding reserves prepared by the Trust’s independent reserve engineers.

Trustee’s Report on Internal Control over Financial Reporting and Report of Independent Registered Public Accounting Firm.

The information required to be furnished pursuant to this item is set forth below and in the “Report of Independent Registered Public Accounting Firm” in Item 8 of this report.

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) promulgated under the Exchange Act. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framework (2013), the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2020.

According to the Internal Control-Integrated Framework (2013), a registrant’s internal control over financial reporting is a process designed by or under the supervision of, its principal executive officer and principal financial officer, or persons performing similar functions, and effected by the registrant’s board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A registrant’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the registrant; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the registrant are being made only in accordance with authorizations of management and directors of the registrant; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the registrant’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Changes in Internal Control over Financial Reporting. There were no changes in the Trust’s internal control over financial reporting during the quarter ended December 31, 2020 that have materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee notes for purposes of clarification that it has no authority over, has not evaluated and makes no statement concerning, the internal control over financial reporting of Avalon.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The Trust has no directors or executive officers. The Trustee is a corporate trustee that may be removed by the affirmative vote of the holders of not less than a majority of the outstanding Trust units, excluding Trust units held by Avalon, at a special meeting of the Trust unitholders at which a quorum is present.

Audit Committee and Nominating Committee

Because the Trust does not have a board of directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

Code of Ethics

The Trust does not have a principal executive officer, principal financial officer, principal accounting officer or controller and, therefore, has not adopted a code of ethics applicable to such persons.

Item 11. Executive Compensation

During the years ended December 31, 2020 and 2019, the Trustee and the Delaware Trustee received administrative fees from the Trust pursuant to the terms of the Trust Agreement. See the disclosures in the section entitled “Liquidity and Capital Resources – Contractual Obligations” in Item 7 of this report for the amounts of such compensation. The Trust does not have any executive officers, directors or employees. Because the Trust does not have a board of directors, it does not have a compensation committee.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners.

The following table sets forth certain information regarding the beneficial ownership of the Trust units as of March 16, 2021 by each person who, to the Trustee’s knowledge, beneficially owns more than 5% of the outstanding Trust units.

Name and Address of Beneficial Owner	Title of Class	Amount and Nature of Beneficial Ownership		Percent of Class (1)
Avalon Energy, LLC 5000 Quorum Drive, Suite 205 Dallas, Texas 75254	Common units		13,125,000		25.0	%

Montare Resources I, LLC (2) 400 East Las Colinas BLVD Irving, Texas 75039	Common units		5,056,912		9.6	%

(1)

Based on 52,500,000 Trust units outstanding as of March 19, 2021.

(2)

The information is based on communication with Montare Resources as of March 19, 2021. According to the filing, Montare and Avalon may be deemed a group for the purposes of Section 13(d)(3) of the Act as a result of the transactions described in Item 4 of the Schedule 13D/A. According to the filing, Montare expressly disclaims beneficial ownership of any securities beneficially owned or acquired by Avalon or any other holder of Common Units.

Security Ownership of Management.

Not applicable.

Changes in Control.

In connection with the Sale Transaction, Avalon borrowed funds to pay a portion of the purchase price for the Underlying Properties and related assets to SandRidge. These funds were obtained as a part of a secured revolving credit agreement from WaFed as described under “General—Sale of Assets by SandRidge to Avalon” in Item 1 of this report. The collateral securing such revolving line of credit includes a pledge of the Trust units owned by Avalon. If Avalon were to default under the WaFed Loan and does not cure such default within the time period provided in the applicable loan documents, WaFed has the right to foreclose upon and take the Trust units.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Certain Relationships and Related Transactions

Avalon (as the assignee of SandRidge) and the Trust are parties to the Administrative Services Agreement and the registration rights agreement. The Trust makes certain payments to Avalon, the Trustee and the Delaware Trustee, and previously made certain payments to SandRidge, pursuant to the Trust Agreement and the Administrative Services Agreement. Descriptions of these agreements are included in “Business” in Item 1 of this report; in “Trustee’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this report; and in Note 7 to the financial statements included in Item 8 of this report. In addition, the description of the Offering included in “Business” in Item 1 of this report is hereby incorporated by reference.

Director Independence

The Trust does not have a board of directors. Further, the Trust relies on an exemption from the director independence requirements of the New York Stock Exchange set forth in Rule 10A-3(c)(7) under the Exchange Act, applicable to listed issuers organized as trusts that do not have a board of directors.

Item 14. Principal Accountant Fees and Services

The Trust does not have an audit committee. Any pre-approval and approval of all services performed by the principal auditor or any other professional service firms and related fees are granted by the Trustee.

The following table presents fees for professional audit services rendered by PricewaterhouseCoopers LLP for the audit of the Trust’s financial statements for 2020 and 2019 and fees billed for other services rendered by PricewaterhouseCoopers LLP.

	2020		2019
Audit fees(1)	$	315,000	$	255,000
Tax fees		311,000		311,000
Total fees	$	626,000	$	566,000

(1)

Fees for audit services in 2020 and 2019 consisted of the audit of the Trust’s annual financial statements and reviews of the Trust’s quarterly financial statements.

PART IV

Item 15. Exhibit and Financial Statement Schedules

The following documents are filed as a part of this report:

(1) Financial Statements

Reference is made to the Index to Financial Statements appearing on page F-1.

(2) Financial Statement Schedules

All financial statement schedules have been omitted because they are not applicable or the required information is presented in the financial statements or notes thereto.

(3) Exhibits

The exhibits below are filed or furnished herewith or incorporated herein by reference.

		Incorporated by Reference
Exhibit No.	Exhibit Description	Form	SEC File No.	Exhibit	Filing Date	Filed or Furnished Herewith
3.1	Certificate of Trust of SandRidge Permian Trust	S-1	333-174492	3.1	05/25/2011
3.2	Amended and Restated Trust Agreement, dated as of August 16, 2011, by and among SandRidge Energy, Inc., The Bank of New York Mellon Trust Company, N.A., and The Corporation Trust Company	8-K	001-35274	4.1	08/19/2011
3.3	Amendment No. 1 to Amended and Restated Trust Agreement, dated June 18, 2012, by The Bank of New York Mellon Trust Company, N.A.	10-Q	001-35274	3.3	08/13/2012
4.1	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934	10-K	001-35274	4.1	03/13/2020
10.1	Perpetual Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and SandRidge Permian Trust	8-K	001-35274	10.3	08/19/2011
10.2	Perpetual Overriding Royalty Interest Conveyance (Development), by and between SandRidge Exploration and Production, LLC and SandRidge Permian Trust	8-K	001-35274	10.4	08/19/2011
10.3	Assignment of Overriding Royalty Interest, by and between Mistmada Oil Company and SandRidge Permian Trust	8-K	001-35274	10.5	08/19/2011
10.4	Term Overriding Royalty Interest Conveyance (PDP), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company	8-K	001-35274	10.1	08/19/2011
10.5	Term Overriding Royalty Interest Conveyance (Development), by and between SandRidge Exploration and Production, LLC and Mistmada Oil Company	8-K	001-35274	10.2	08/19/2011
10.6	Administrative Services Agreement, by and between SandRidge Energy, Inc. and SandRidge Permian Trust	8-K	001-35274	10.6	08/19/2011
10.7	Registration Rights Agreement, dated as of August 16, 2011, by and between SandRidge Energy, Inc. and SandRidge Permian Trust	8-K	001-35274	10.10	08/19/2011
10.8	Assignment, Assumption and Consent Agreement dated as of November 1, 2018, by and among SandRidge Energy, Inc., Avalon Energy, LLC, and SandRidge Permian Trust	8-K	001-35274	10.1	11/05/2018
23.1	Consent of Netherland, Sewell & Associates, Inc.					*
31.1	Section 302 Certification					*
32.1	Section 906 Certification					*
99.1	Report of Netherland, Sewell & Associates, Inc.					*

Item 16. Form 10-K Summary

Not Applicable.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SANDRIDGE PERMIAN TRUST

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

	By:	/s/ Sarah Newell
		Sarah Newell
		Vice President

March 26, 2021

The Registrant, SandRidge Permian Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no additional signatures are available, and none have been provided. In signing the report above, the Trustee does not imply that it has performed any such function or that any such function exists pursuant to the terms of the Trust Agreement under which it serves.

INDEX TO FINANCIAL STATEMENTS

			Page(s)
Report of Independent Registered Public Accounting Firm
Statements of Assets and Trust Corpus at December 31, 2020 and 2019			F-1
Statements of Distributable Income for the Years Ended December 31, 2020 and 2019			F-2
Statements of Changes in Trust Corpus for the Years Ended December 31, 2020 and 2019			F-3
Notes to Financial Statements			F-4

Report of Independent Registered Public Accounting Firm

To the Unitholders of SandRidge Permian Trust and The Bank of New York Mellon Trust Company, N.A., as Trustee

Opinion on the Financial Statements

We have audited the accompanying statements of assets and trust corpus of SandRidge Permian Trust (the “Trust”) as of December 31, 2020 and 2019, and the related statements of distributable income and changes in trust corpus for the years then ended, including the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the assets and trust corpus of the Trust as of December 31, 2020 and 2019, and its distributable income and its changes in trust corpus for the years then ended in conformity with the modified cash basis of accounting described in Note 3.

Substantial Doubt about the Trust’s Ability to Continue as a Going Concern

The accompanying financial statements have been prepared assuming that the Trust will continue as a going concern. As discussed in Note 2 to the financial statements, the Trust had cash available for distribution of approximately $2.4 million, on a cumulative basis, for the four consecutive quarters ended December 31, 2020, which is less than the $5.0 million required by the Trust Agreement. As a result, the Trust was required to dissolve and commence winding up of its business and affairs beginning as of the close of business on February 26, 2021 which raises substantial doubt about its ability to continue as a going concern. Management's plans in regard to these matters are also described in Note 2. The financial statements do not include any adjustments that might result from the outcome of this uncertainty.

Basis for Opinion

These financial statements are the responsibility of the Trust’s management. Our responsibility is to express an opinion on the Trust’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Trust in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Trust is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Trust's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Basis of Accounting

As described in Note 3, these financial statements were prepared on the modified cash basis of accounting, which is a comprehensive basis of accounting other than generally accepted accounting principles.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The Impact of Proved Oil and Natural Gas Reserves on Net Investment in Royalty Interests

The Trust’s net investment in royalty interests balance was $10.1 million as of December 31, 2020, and amortization of investment in royalty interests for the year ended December 31, 2020 was $4.0 million. As described in Note 3 to the financial statements, 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. As disclosed by management, there are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future revenues, production volumes, rates of production and timing of development expenditures, including many factors beyond the Trust’s control. Estimating reserves is very complex and relies on assumptions and subjective interpretations of available geologic, geophysical, engineering and production data, and the accuracy of reserve estimates is a function of the quality and quantity of available data, engineering and geological interpretation and judgment. The proved oil, natural gas and natural gas liquids (“NGL”) reserves attributable to the Royalty Interests are estimated by independent petroleum engineers (the “specialists”).

The principal considerations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on the Trust’s net investment in royalty interests is a critical audit matter are (i) the significant judgment by management, including use of specialists, when developing the estimates of proved oil and natural gas reserves, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of the oil and natural gas reserve volumes.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the oil and natural gas reserve volumes. As a basis for using this work, the specialists’ qualifications were understood and the Trust’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists, and an evaluation of the specialists’ findings.

Third Quarter Impairment Assessment of Net Investment in Royalty Interests

The net investment in royalty interests balance was $10.1 million as of December 31, 2020, and impairment of investment in royalty interests for the year ended December 31, 2020 was $83.5 million, of which $6.4 million related to the third quarter ended September 30, 2020. As described in Note 3, on a quarterly basis, management evaluates the carrying value of the investment in royalty interests by comparing the undiscounted cash flows expected to be realized from the Royalty Interests to the carrying value. If the expected future undiscounted cash flows are less than the carrying value, management recognizes an impairment loss for the difference between the carrying value and the estimated fair value of the Royalty Interests, which is determined using either a market-based or income-based approach, depending on which is deemed more relevant in the circumstances. The income-based approach estimates fair value using future cash flows of the net oil, natural gas and NGL reserves attributable to the Royalty Interests discounted at a relevant market participant discount rate; oil and natural gas futures prices readily available in the public market adjusted for differentials; and estimated future production volumes.

The principal considerations for our determination that performing procedures relating to the third quarter impairment assessment of net investment in royalty interests is a critical audit matter are (i) the significant judgment by management, including the use of specialists, when developing the fair value measurement of the net investment in royalty interests; and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to future production volumes and the discount rate.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial statements. These procedures included, among others (i) testing management’s process for developing the fair value measurement of the net investment in royalty interests; (ii) evaluating the appropriateness of the income-based approach; (iii) testing the completeness and accuracy of underlying data used in the model; and (iv) evaluating the reasonableness of significant assumptions used by management related to future production volumes and the discount rate. Evaluating the reasonableness of the discount rate involved comparing the rate used to observable market data. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved oil and natural gas reserves volumes as stated in the Critical Audit Matter titled “The Impact of Proved Oil and Natural Gas Reserves on Net Investment in Royalty Interests” and the reasonableness of the future production volumes. As a basis for using this work, the specialists’ qualifications were understood and the Trust’s relationship with the specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

March 26, 2021

We have served as the Trust’s auditor since 2011.

SANDRIDGE PERMIAN TRUST

STATEMENTS OF ASSETS AND TRUST CORPUS

(In thousands, except unit data)

	December 31,
	2020			2019
ASSETS
Cash and cash equivalents	$	7,216		$	4,698
Investment in royalty interests		154,628			549,831
Less: accumulated amortization and impairment		(144,514	)		(447,373	)
Net investment in royalty interests		10,114			102,458
Total assets	$	17,330		$	107,156
TRUST CORPUS
Trust corpus, 52,500,000 common units issued and outstanding at December 31, 2020 and 2019	$	17,330		$	107,156

The accompanying notes are an integral part of these financial statements.

F-1

SANDRIDGE PERMIAN TRUST

STATEMENTS OF DISTRIBUTABLE INCOME

(In thousands, except unit and per unit data)

	Years Ended December 31,
	2020			2019
Revenues
Royalty income	$	9,704		$	22,442
Proceeds from sale of Trust assets		4,874			—
Total revenues		14,578			22,442
Expenses
Post-production expenses		33			50
Property taxes		2,979			—
Production taxes		465			1,061
Franchise taxes		36			47
Trust administrative expenses		1,985			1,734
Cash reserves (used) withheld for current Trust expenses, net of amounts (withheld) used		(2,391	)		2,261
Total expenses		3,107			5,153
Less proceeds withheld from sale of Trust assets		4,874			—
Distributable income available to unitholders		6,597			17,289
Distributable income per unit	$	0.126		$	0.329

The accompanying notes are an integral part of these financial statements.

F-2

SANDRIDGE PERMIAN TRUST

STATEMENTS OF CHANGES IN TRUST CORPUS

(In thousands)

	Years Ended December 31,
	2020			2019
Trust corpus, beginning of year	$	107,156		$	115,225
Amortization of investment in royalty interests		(3,995	)		(10,399	)
Impairment of investment in royalty interests		(83,474	)		—
Net cash reserves (used) withheld		(2,391	)		2,261
Distributable income		6,597			17,289
Distributions paid or payable to unitholders		(6,563	)		(17,220	)
Trust corpus, end of year	$	17,330		$	107,156

The accompanying notes are an integral part of these financial statements.

F-3

SANDRIDGE PERMIAN TRUST

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 (the “Offering”). 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.

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 to Avalon Energy, LLC, a Texas limited liability company (“Avalon Energy”). 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 this transaction (the “Sale Transaction”), Avalon Energy assumed all of SandRidge’s obligations under the conveyances, the Trust Agreement and the administrative services agreement between SandRidge and the Trust. As a result, Avalon is providing accounting, tax preparation, bookkeeping and informational services to the Trust. Avalon Energy, Avalon Exploration and Production LLC, its parent company, and Avalon TX Operating LLC, the operator of the Underlying Properties, are collectively referred to as “Avalon” in this report. In addition, SandRidge assigned its rights to Avalon under the registration rights agreement between SandRidge and the Trust. As of December 31, 2020, 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, or involvement with any aspect of the oil and natural gas operations, operating or capital costs or other activities 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.

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.

2. Early Termination of the Trust and Going Concern

Avalon’s Financial Condition. The reduced demand for crude oil in the global market resulting from the economic effects of the COVID-19 pandemic and the dramatic reduction from mid-February to late April 2020 in the benchmark price of crude oil, which continued to fluctuate throughout 2020, have had a negative impact on Avalon’s financial condition. Avalon informed the Trustee that during 2020 Avalon shut in oil and gas wells subject to the Royalty Interests (“Trust Wells”) that are not capable of producing oil and natural gas in paying quantities, as permitted under the Conveyances, in an effort to reduce leasehold operating expenses (“LOE”). These Trust Wells were not necessary to hold the leasehold interests burdened by the Trust’s Royalty Interests. Avalon shut in 139 Trust Wells and 114 Trust Wells during the twelve-month periods ended December 31, 2019 and 2020, respectively.

F-4

F-5

Unaudited Pro Forma Information

The unaudited proforma statements of distributable income for the twelve months ended December 31, 2019 and 2020 have each been prepared with the assumption that the Montare Sale occurred effective January 1, 2019 (for production periods starting September 1, 2018).

The unaudited proforma financial information does not purport to be indicative of the results of operations or the financial condition which would have actually resulted if the Montare Sale actually occurred on the dates presented or to project the Trust’s result of operations or financial position for any future period. The unaudited proforma financial information is not predictive of future results of operations or financial condition of the Trust, as the Trust’s future results of operation and financial condition may differ significantly from the proforma amounts reflected herein due to a variety of factors.

	Twelve Months Ended
	December 31,
		2020	2019

		(In thousands)
Total revenues		2,205		8,762
Distributable income available to unitholders		1,834		4,530

The above transactions assume the proceeds on the sale of Trust assets of $4,874,000 were received in 2019.

F-6

Accordingly, the Trustee is required to sell all of the Trust’s assets, 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, which is expected to include the establishment of cash reserves in such amounts as the Trustee in its discretion deems appropriate for the purpose of making reasonable provision for all claims and obligations of the Trust, including any contingent, conditional or unmatured claims and obligations, in accordance with the Delaware Statutory Trust Act. The sale process will involve costs that will reduce the amounts of any distributions to Trust unitholders during the winding up period. As required by the Trust Agreement, the Trustee has engaged a third-party advisor to assist with the marketing and sale of the Royalty Interests. As provided in the Trust Agreement, Avalon has a right of first refusal with respect to any sale of Royalty Interests to a third party. The Trustee expects to complete the sale of the Royalty Interests by the end of the third quarter of 2021 and distribute the net proceeds of the sale to the Trust unitholders on the following quarterly payment date, and the Trust units are expected to be canceled shortly thereafter. Pending the sale or sales of the Royalty Interests, and subject to the effective date and other terms of such sale or sales, the Trust anticipates that it will continue to receive income, if any, attributable to the Royalty Interests and will continue to make quarterly distributions to Trust unitholders to the extent there is available cash after payment of Trust expenses and additions to cash reserves. The Trust will remain in existence until the filing of a certificate of cancellation with the Secretary of State of the State of Delaware following the completion of the winding up process.

3. 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.

F-7

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 either a market-based or income-based approach, depending on which is deemed more relevant in the circumstances. The income-based approach uses future cash flows of the net oil, natural gas and NGL reserves attributable to the Royalty Interests, discounted at a relevant market participant discount rate. 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 future production volumes, which are derived from 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. During the year ended December 31, 2020, due to the decline in oil and gas prices, the Trust recorded impairments in the carrying value of the Investment in Royalty Interests in aggregate of $83.5 million, of which, $77.1 million related to the first quarter ended March 31, 2020, and $6.4 million related to the third quarter ended September 30, 2020. The impairments resulted in non-cash charges to trust corpus and did not affect the Trust’s distributable income. There were no impairments in the carrying value of the Investment in Royalty Interests during 2019. 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 6 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.

F-8

4. 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 2019 Texas franchise tax of approximately $0.1 million during the year ended December 31, 2020. The Trust paid its 2018 Texas franchise tax of approximately $0.1 million during the year ended December 31, 2019. The Trust expects to pay its estimated 2020 Texas franchise tax liability of approximately $0.1 million during the year ending December 31, 2021. Further, the Trust’s tax years 2016 to present remain open for examination with respect to Texas franchise tax.

The Trust records Texas property taxes when paid. The Trust paid its 2020 property taxes of approximately $1.3 million in December 2020. 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.

5. 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:

	Covered Production Period		Date Declared	Date Paid	Total Distribution Paid		Distribution Per Common Unit
						(in millions)
Calendar Quarter 2020
First Quarter		September 1, 2019 - November 30, 2019	January 23, 2020	February 28, 2020	$	4.2	$	0.080
Second Quarter (1)		December 1, 2018 - February 29, 2020	April 23, 2020	N/A		—		—
Third Quarter		March 1, 2020 - May 31, 2020	July 23, 2020	August 31, 2020	$	0.6	$	0.012
Fourth Quarter		June 1, 2020 - August 31, 2020	October 22, 2020	November 25, 2020	$	1.7	$	0.033

Calendar Quarter 2019
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
Third Quarter		March 1, 2019 - May 31, 2019	July 24, 2019	August 23, 2019	$	4.7	$	0.089
Fourth Quarter		June 1, 2019 - August 31, 2019	October 24, 2019	November 24, 2019	$	3.8	$	0.073

(1) Avalon did not make a distribution of revenue to the Trust for the production period from December 1, 2019 to February 29, 2020.

F-8

Subsequent 2020 Distributions to Unitholders. In April 2020, Avalon informed the Trustee that due to Avalon’s decision to prioritize the preservation of oil and gas leases burdened by the Royalty Interests, coupled with the sharp decline in oil and gas prices since the beginning of 2020, as discussed elsewhere in this Quarterly Report, at that time Avalon did not believe it would be able to generate sufficient cash for quarterly payments to the Trust for the foreseeable future. However, with the partial recovery of crude oil prices since the end of April 2020 and with increased cost-cutting efforts, Avalon was able to make a payment of approximately $1.7 million to the Trust for the three-month period ended June 30, 2020 (which primarily relates to production attributable to the Trust’s Royalty Interests from March 1, 2020 to May 31, 2020), and the Trust made a quarterly distribution to Trust unitholders of $652,000 for that period. Avalon was also able to make a payment of approximately $2.7 million to the Trust for the three-month period ended September 30, 2020 (which primarily relates to production attributable to the Trust’s Royalty Interests from June 1, 2020 to August 31, 2020), and the Trust made a quarterly distribution to Trust unitholders of approximately $1.7 million for that period. See “Distribution to Unitholders” in Note 9. “Subsequent Events” for a discussion of the quarterly distribution made to Trust unitholders in February 2021. In addition, see Note 2. “Early Termination of the Trust and Going Concern” for a discussion of the early termination of the Trust in February 2021.

6. 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, 2020 or 2019.

F-9

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.

7. 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, 2020 and 2019 totaled approximately $161,000 and $158,000, 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, 2020, the Trust paid administrative fees in the amount of $300,000 to Avalon. 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.

8. Major Customers

For the years ended December 31, 2020 and 2019, 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)
2020
Ace Energy Solutions	$	9,188		94.9	%

2019
Enterprise Crude Oil LLC	$	17,063		81.2	%
ConocoPhillips Company	$	3,951		18.8	%

F-10

9. Subsequent Events

Distribution to Unitholders. On January 28, 2021, the Trust announced a distribution of approximately $3.9 million, or $0.075 per unit, reflecting the fair value received by the Trust, less cash reserves withheld by the Trust as described below, for the portion of the Trust’s Royalty Interests required to be released upon the sale by Avalon of a portion of the Underlying Properties to Montare on October 13, 2020. The distribution occurred on or about February 26, 2021 to holders of record as of the close of business on February 12, 2021. The Trust also announced that there would be no cash distribution paid for the three-month period ended December 31, 2020 (with respect to production attributable to the Trust’s Royalty Interests from September 1, 2020 to November 30, 2020) as costs, charges and expenses attributable to the Underlying Properties were more than the revenue received from the sale of oil, natural gas and other hydrocarbons produced from such properties, as reported by Avalon. Distributable income for the period would have been zero without the proceeds reflecting the fair value received by the Trust for the portion of the Trust’s Royalty Interests required to be released upon the sale by Avalon of a portion of the Underlying Properties to Montare. Distributable income from production for the three-month period from September 1, 2020 to November 30, 2020 was calculated as follows (in thousands, except for unit and per unit amounts):

Revenues
Proceeds from sale of Trust assets(1)	$	4,874
Royalty income		665
Total revenues		5,539
Expenses
Post-production expenses		1
Production taxes		32
Cash reserves withheld by Trustee(2)		686
Total expenses		719
Distributable income	$	4,820
Additional cash reserve(3)		884
Distributable income available to unitholders	$	3,936
Distributable income per unit (52,500,000 units issued and outstanding)	$	0.075

(1) Cash received October 2020.

(2) Includes amounts withheld for payment of future Trust administrative expenses.

(3) Cash reserve increase for the payment of future known, anticipated or contingent expenses or liabilities.

Commencing with the distribution to unitholders paid in the first quarter of 2019, the Trustee has withheld the greater of $190,000 or 3.5% of the funds otherwise available for distribution to Trust unitholders each quarter to gradually increase cash reserves for the payment of future known, anticipated or contingent expenses or liabilities by a total of approximately $3,275,000. In light of the fact that there would be no distribution from production for the three-month period ended December 31, 2020 (with respect to production attributable to the Trust’s royalty interests from September 1, 2020 to November 30, 2020), the Trustee elected to withhold approximately $884,000, the remaining amount needed to reach its targeted cash reserve, in connection with the distribution made in February 2021. Cash held in reserve will be invested as required by the Trust Agreement. Any cash reserved in excess of the amount necessary to pay or provide for the payment of future known, anticipated or contingent expenses or liabilities of the Trust eventually will be distributed to unitholders, together with interest earned on the funds. The Trustee may increase or decrease the targeted cash reserve amount at any time, and may increase or decrease the rate at which it withholds funds to build the cash reserve at any time, without advance notice to Trust unitholders.

F-11

Dissolution of the Trust. Cash available for distribution for the four consecutive quarters ended December 31, 2020, on a cumulative basis, totaled approximately $2.4 million, due in part to Avalon’s inability to make the May 2020 Quarterly Payment to the Trust. As a result, the Trust was required to dissolve and commence winding up beginning as of the close of business on February 26, 2021. See “Early Termination of the Trust; Sale of Trust Assets. ” in Note 2 above for further discussion.

Repayment Agreement. On March 1, 2021, the Trust and Avalon entered into a repayment agreement setting forth the terms by which Avalon has agreed to pay the May 2020 Quarterly Payment to the Trust, together with accrued interest (the “Repayment Agreement”). Beginning with the quarterly distribution paid to Trust unitholders on or about February 26, 2021 (the “February Distribution”), Avalon will apply towards the payment of the May 2020 Quarterly Payment the full amount of each quarterly cash distribution, if any, to which Avalon, as a unitholder of the Trust, is entitled (each such cash distribution, a “Company Distribution Amount”), until the May 2020 Quarterly Payment, together with accrued interest, has been paid in full to the Trust, subject to any obligations Avalon may have to repay the WaFed Loan that are not waived as provided in the Repayment Agreement. Promptly upon receipt, Avalon deposited the $984,375 received as its portion of the February Distribution into a repayment account established by the Trustee on behalf of the Trust (the “Repayment Account”) pursuant to the terms of the Repayment Agreement. Avalon will deposit each additional Company Distribution Amount into the Repayment Account promptly, but in no event later than the next business day, after the Company’s receipt of any such Company Distribution Amount.

The Repayment Agreement also provides that if any third party agrees to acquire Avalon, whether pursuant to a merger, consolidation, purchase of all or substantially all of the assets of Avalon, or other similar transaction or series of transactions (an “Avalon Sale Transaction”), then, subject to any obligations Avalon may have to repay the WaFed Loan in connection with any such transaction that are not waived as provided in the Repayment Agreement, Avalon will pay to the Trust from cash received in an Avalon Sale Transaction an amount equal to (i) the difference between (A) the aggregate amounts deposited in the Repayment Account pursuant to the Agreement at the time the Avalon Sale Transaction is consummated and (B) the then outstanding balance of the May 2020 Quarterly Payment together with all accrued and unpaid interest thereon to the date of payment of such outstanding balance (the “Balance Amount”) or (ii) where the amount of cash received in the Avalon Sale Transaction is less than the Balance Amount, all of the cash received in the Avalon Sale Transaction. Avalon agrees that it will pay such amount to the Trust promptly, but in no event later than the next business day, after the closing of any such Avalon Sale Transaction. If Avalon is unable to pay the Balance Amount in full upon the closing of an Avalon Sale Transaction, Avalon has agreed, subject to any obligations Avalon may have to repay the WaFed Loan in connection with any such transaction that are not waived as provided in the Repayment Agreement, to pledge to the Trust, to secure the payment of the outstanding portion of the Balance Amount, any non-cash consideration that Avalon receives from such Avalon Sale Transaction or similar transaction.

F-12

10. 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, 2020 and 2019 is as follows:

	Year Ended December 31, 2020
			For the period
	Modified Cash Basis(1)		September 1, 2019 to December 31, 2019			December 1, 2019 to February 29, 2020		September 1, 2020 to December 31, 2020		Accrual Basis (2)
Production Data (Unaudited)
Oil (MBbls)		241.1		(123.4	)		86.1		22.0		225.8
NGL (MBbls)		28.7		(12.8	)		9.3		2.3		27.5
Natural Gas (MMcf)		106.7		(48.7	)		34.7		7.9		100.5
Combined equivalent volumes (MBoe)(3)		287.6		(144.3	)		101.2		25.6		270.1

Royalty Income (in thousands)	$	9,685	$	(7,087	)		4,904	$	884	$	8,386
Expenses (in thousands):
Post-production costs		33		(20	)		22		2		37
Property taxes		2,979		(1,719	)		—		43		1,303
Production taxes		465		(338	)		228		42		397
	$	6,208	$	(5,010	)		4,654	$	797	$	6,649

	Year Ended December 31, 2019
			For the period
	Modified Cash Basis(4)		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

(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, 2019 to August 31, 2020.

(2) Production volumes attributable to the Royalty Interests and related revenues and expenses, presented on an accrual basis for the years ended December 31, 2020 and 2019 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 2019 net revenue distributions to the Trust represents production from September 1, 2018 to August 31, 2019.

F-13

Capitalized Costs Related to Oil and Natural Gas Producing Activities

The Trust’s capitalized costs consisted of the following (in thousands):

	December 31,
	2020			2019
Investment in royalty interests
Proved(1)	$	154,628		$	549,831
Unproved		—			—
Total investment in royalty interests		154,628			549,831
Less accumulated amortization and impairment		(144,514	)		(447,373	)
Net investment in royalty interests	$	10,114		$	102,458

(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, 2020 or 2019.

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 2020 and 2019 are shown in the following table (in thousands):

	December 31, (1)
	2020		2019
Revenues	$	8,405	$	21,663
Expenses(2)
Post-production costs		37		54
Property taxes		1,303		1,676
Production taxes		397		1,021
Amortization expense(3)		3,995		10,399
Income before income taxes		2,673		8,513
Income taxes(4)		14		36
Results of operations for oil and natural gas producing activities (excluding general and administrative costs of the Trust)	$	2,659	$	8,477

(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. Non-cash impairment of $83.5 million recorded during 2020 was charged to trust corpus and did not affect the Trust’s distributable income.

(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.

F-14

Based on its review of the estimates of proved reserves made by the independent petroleum engineers, Avalon 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 Avalon’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, 2020 and 2019.

	Oil (MBbls)			NGL (MBbls)			Natural Gas (MMcf)(1)
Proved developed and undeveloped reserves
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
Revisions of previous estimates		(97.7	)		(14.8	)		(30.7	)
Sales of reserves in place		(2,800.3	)		(296.3	)		(968.2	)
Production(2)		(225.8	)		(27.5	)		(100.5	)
As of December 31, 2020		794.9			72.9			259.7

Proved developed reserves(3)
As of December 31, 2019		3,918.7			411.5			1,359.1
As of December 31, 2020		794.9			72.9			259.7
Proved undeveloped reserves(3)
As of December 31, 2019		—			—			—
As of December 31, 2020		—			—			—

(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 a large net reduction to reserves during 2020 associated with proved properties of as a result of the sale by Avalon of wells and related assets to Montare. The Trust recognized net reductions to reserves associated with proved properties of approximately 571.6 MBoe as a result of pricing during 2019.

F-15

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, 2020 and 2019. The calculated weighted average per unit prices for the Trust’s proved reserves and future net revenues were as follows;

	December 31,
	2020		2019
Oil (per barrel)	$	36.82	$	51.58
NGL (per barrel)	$	14.63	$	19.55
Natural Gas (per Mcf)	$	0.74	$	0.88

•

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,
	2020			2019
Future cash inflows from production	$	30,527		$	211,362
Future production costs(1)		(2,372	)		(16,434	)
Future income taxes		(51	)		(350	)
Undiscounted future net cash flows		28,105			194,578
10% annual discount		(14,707	)		(90,764	)
Standardized measure of discounted future net cash flows	$	13,398		$	103,814

(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, 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
Revenues less post-production and other costs		(6,649	)
Net changes in prices, production and other costs		(30,607	)
Revisions of previous quantity estimates		(1,947	)
Accretion of discount		9,478
Net changes in income taxes		163
Sales of reserves in place		(47,372	)
Timing differences and other(1)		(13,482	)
Net change for the year		(90,416	)
Present value as of December 31, 2020	$	13,398

(1) Changes in timing differences and other are related to revisions in the estimated timing of production and, as applicable, development.

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