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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, 2019  ☐
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: 1-8424 Sabine Royalty Trust (Exact name of registrant as specified in its charter)  Texas

71-0162300(State or other jurisdiction
of incorporation or organization)

(I.R.S. Employer
Identification No.)Simmons Bank
Suite 850 2911 Turtle Creek Boulevard
Dallas, Texas

75219(Address of principal executive offices)

(Zip Code) Registrants telephone number, including area code: 855-588-7839 Securities registered pursuant to Section 12(b) of the Act:  Title of Each Class

Trading
Symbol

Name of Each Exchange
on Which RegisteredUnits of Beneficial Interest

SBR

New York Stock Exchange 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 ☒ 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 ☒ 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 ☒    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 (§ 232.405 of this chapter) 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 ☐  Smaller reporting company ☐  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 is a shell company (as defined in Rule 12b-2 of the Act).
Yes ☐    No ☒ The aggregate market value of units of beneficial interest of the registrant (based on the closing sale price on the New York Stock Exchange as of the
last business day of its most recently completed second fiscal quarter) held by non-affiliates of the registrant was approximately $705 million. At March 2, 2020, there were 14,579,345 units of beneficial interest outstanding. DOCUMENTS INCORPORATED BY REFERENCE None




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TABLE OF CONTENTS  PagePART IItem 1.

Business


1Description of the Trust


1Assets of the Trust


2Liabilities of the Trust


2Duties and Limited Powers of Trustee


3Liabilities of Trustee


3Duration of Trust


3Voting Rights of Unit Holders


4Description of Units


4Distributions of Distributable Income


5Transfer


5Reports to Unit Holders


5Widely Held Fixed Investment Trust Reporting Information


5Liability of Unit Holders


6Possible Divestiture of Units


6Federal Taxation


7State Tax Considerations


9Regulation and Prices


11Regulation


11Prices


16Item 1A.

Risk Factors


16Item 1B.

Unresolved Staff Comments


20Item 2.

Properties


20Title


21Reserves


21Item 3.

Legal Proceedings


30Item 4.

Mine Safety Disclosures


30PART IIItem 5.

Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases
 of Equity Securities


31Item 6.

Selected Financial Data


31Item 7.

Trustees Discussion and Analysis of Financial Condition and Results of Operations


31Item 7A.

Quantitative and Qualitative Disclosures About Market Risk


35Item 8.

Financial Statements and Supplementary Data


36Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure


48Item 9A.

Controls and Procedures


48Item 9B.

Other Information


51PART IIIItem 10.

Directors and Executive Officers and Corporate Governance


51Item 11.

Executive Compensation


51Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters


51Item 13.

Certain Relationships and Related Transactions, and Director
Independence


52Item 14.

Principal Accounting Fees and Services


52PART IVItem 15.

Exhibits, Financial Statement Schedules


52  i




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PART I Item 1.Business. DESCRIPTION OF THE TRUST Sabine Royalty Trust (the Trust) is an express trust formed under the laws of the State of Texas by the Sabine Corporation Royalty Trust
Agreement (the Trust Agreement) made and entered into effective as of December 31, 1982, between Sabine Corporation, as trustor, and InterFirst Bank Dallas, N.A. (InterFirst), as trustee. The current trustee of the Trust is
Simmons Bank, an Arkansas state-chartered bank (Simmons Bank). In accordance with the successor trustee provisions of the Trust Agreement, Simmons Bank, as trustee of the Trust (the Trustee) is subject to all terms and
conditions of the Trust Agreement. The principal office of the trust (sometimes referred to herein as the Registrant) is located at 2911 Turtle Creek Boulevard, Suite 850, Dallas, Texas, 75219. The telephone number of the trust is
1-855-588-7839. On January 9, 2014, Bank of America, N.A. (as successor to InterFirst Bank Dallas, N.A.) gave notice to Unit holders that it was
resigning as the Trustee subject to certain conditions including the appointment of Southwest Bank as trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest Bank as successor trustee
of the Trust, once Bank of America, N.A.s resignation took effect. The effective date of Bank of America, N.A.s resignation and the effective date of Southwest Banks appointment as successor trustee was May 30, 2014. Effective October 19, 2017, Simmons First National Corporation (SFNC) completed its acquisition of First Texas BHC, Inc., the parent company
of Southwest Bank. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank with Simmons Bank effective February 20, 2018. The defined term
Trustee as used herein shall refer to Bank of America, N.A. for periods prior to May 30, 2014 and shall refer to Southwest Bank for periods from May 30, 2014 through February 19, 2018 and shall refer to Simmons Bank for periods on and
after February 20, 2018. The Trust maintains an Internet website, and as a result, reports such as its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports filed or
furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, will now be made available at http://www.sbr-sabine.com as soon as reasonably practicable after such information is electronically filed
with or furnished to the SEC. On November 12, 1982, the shareholders of Sabine Corporation approved and authorized Sabine Corporations
transfer of royalty and mineral interests, including landowners royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interests,
in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas (the Royalty Properties) to the Trust. The conveyances of the Royalty Properties to the
Trust were effective with respect to production as of 7:00 a.m. (local time) on January 1, 1983. In order to avoid uncertainty under
Louisiana law as to the legality of the Trustees holding record title to the Royalty Properties located in that state, title to such properties has historically been held by a separate trust formed under the laws of Louisiana, the sole
beneficiary of which was the Trust. Sabine Louisiana Royalty Trust was a passive entity, with the trustee thereof, Hibernia National Bank in New Orleans, having only such powers as were necessary for the collection of and distribution of
revenues from and the protection of the Royalty Properties located in Louisiana and the payment of liabilities of Sabine Louisiana Royalty Trust. Simmons Bank now serves as Trustee of the Sabine Louisiana Royalty Trust, since Louisiana law now
permits an out-of-state bank to act in this capacity. A separate trust also was established to hold record title to the Royalty Properties located in Florida.
Legislation was adopted in Florida in 1992 that eliminated the provision of Florida law that prohibited the Trustee from holding record title to the Royalty  1




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Properties located in that state. In November 1993, record title to the Royalty Properties held by the trustee of Sabine Florida Land Trust was transferred to the Trustee. As used herein,
the term Royalty Properties includes the Royalty Properties held directly by the Trust and the Royalty Properties located in Louisiana and Florida that were held indirectly through the Trusts ownership of 100 percent
beneficial interest of Sabine Louisiana Royalty Trust and Sabine Florida Land Trust. In discussing the Trust, this report disregards the technical ownership formalities described in this paragraph, which have no effect on the tax or accounting
treatment of the Royalty Properties, since the observance thereof would significantly complicate the information presented herein without any corresponding benefit to Unit holders. Certificates evidencing units of beneficial interest (the Units) in the Trust were mailed on December 31, 1982 to the shareholders of
Sabine Corporation of record on December 23, 1982, on the basis of one Unit for each outstanding share of common stock of Sabine Corporation. The Units are listed and traded on the New York Stock Exchange under the symbol SBR. In May 1988, Sabine Corporation was acquired by Pacific Enterprises, a California corporation. Through a series of mergers, Sabine Corporation was
merged into Pacific Enterprises Oil Company (USA) (Pacific (USA)), a California corporation and a wholly owned subsidiary of Pacific Enterprises, effective January 1, 1990. This acquisition and the subsequent mergers had no effect
on the Units. Pacific (USA), as successor to Sabine Corporation, assumed by operation of law all of Sabine Corporations rights and obligations with respect to the Trust. References herein to Pacific (USA) shall be deemed to include Sabine
Corporation where appropriate. In connection with the transfer of the Royalty Properties to the Trust upon its formation, Sabine Corporation had
reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. In January 1993, Pacific (USA) completed the sale of substantially all of Pacific (USA)s producing oil and gas assets to
Hunt Oil Company. The sale did not include the executive rights relating to the Royalty Properties, and Pacific (USA)s ownership of such rights was not affected by the sale. The following summaries of certain provisions of the Trust Agreement are qualified in their entirety by reference to the Trust Agreement itself, which
is an exhibit to the Form 10-K and available upon request from the Trustee. The definitions, formulas, accounting procedures and other terms governing the Trust are complex and extensive and no attempt
has been made below to describe all such provisions. Capitalized terms not otherwise defined herein are used with the meanings ascribed to them in the Trust Agreement. Assets of the Trust The Royalty
Properties are the only assets of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. Pending such payment of expenses and distribution to Unit holders, cash may be invested by
the Trustee only in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest bearing accounts in FDIC-insured state or national banks (including the Trustee)
so long as the entire amount in such accounts is at all times fully insured by the FDIC. See Duties and Limited Powers of Trustee below. Liabilities of the Trust Because of the passive nature of the Trusts assets and the restrictions on the power of the Trustee to incur
obligations, it is anticipated that the only liabilities the Trust will incur are those for routine administrative expenses, such as trustees fees, accounting, engineering, legal and other professional fees. The total general and
administrative expenses for the trust for 2019 were $2,857,442 of which, pursuant to the terms of the Trust Agreement, $431,548 was paid to Simmons Bank, as Trustee, and $1,294,648 was paid to Simmons Bank as escrow agent.  2




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Duties and Limited Powers of Trustee The duties of the Trustee are specified in the Trust Agreement and by the laws of the State of Texas. The basic function of the Trustee is to collect
income from the Trust properties, to pay out of the Trusts income and assets all expenses, charges and obligations, and to pay available income to Unit holders. Since Pacific (USA) has retained the executive rights with respect to the minerals
included in the Royalty Properties and the right to receive any future bonus payments or delay rentals resulting from leases with respect to such minerals, the Trustee is not required to make any investment or operating decision with respect to the
Royalty Properties. The Trust has no employees. Administrative functions of the Trust are performed by the Trustee. The Trustee has the discretion to establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that otherwise
is not currently due and payable. The Trustee has the power to borrow funds required to pay liabilities of the Trust as they become due and pledge or otherwise encumber the Trusts properties if it determines that the cash on hand is
insufficient to pay such liabilities. Borrowings must be repaid in full before any further distributions are made to Unit holders. All distributable income of the Trust is distributed on a monthly basis. The Trustee is required to invest any cash
being held by it for distribution on the next Distribution Date or as a reserve for liabilities in certificates of deposit, United States government securities, repurchase agreements secured by United States government securities or other interest
bearing accounts in FDIC-insured state or national banks (including the Trustee) so long as the entire amount in such accounts is at all times fully insured by the FDIC. The Trustee furnishes Unit holders with periodic reports. See
Item 1  Description of Units  Reports to Unit Holders. The Trust Agreement grants the Trustee only such rights
and powers as are necessary to achieve the purposes of the Trust. The Trust Agreement prohibits the Trustee from engaging in any business, commercial or, with certain exceptions, investment activity of any kind and from using any portion of the
assets of the Trust to acquire any oil and gas lease, royalty or other mineral interest other than the Royalty Properties. The Trustee may sell Trust properties only as authorized by a vote of the Unit holders, or when necessary to provide for the
payment of specific liabilities of the Trust then due or upon termination of the Trust. Pledges or other encumbrances to secure borrowings are permitted without the authorization of Unit holders if the Trustee determines such action is advisable.
Any sale of Trust properties must be for cash unless otherwise authorized by the Unit holders or unless the properties are being sold to provide for the payment of specific liabilities of the Trust then due, and the Trustee is obligated to
distribute the available net proceeds of any such sale to the Unit holders. Liabilities of Trustee The Trustee is to be indemnified out of the assets of the Trust for any liability, expense, claim, damage or other loss incurred by it in the performance
of its duties unless such loss results from its negligence, bad faith or fraud or from its expenses in carrying out such duties exceeding the compensation and reimbursement it is entitled to under the Trust Agreement. The Trustee can be reimbursed
out of the Trust assets for any liability imposed upon the Trustee for its failure to ensure that the Trusts liabilities are satisfiable only out of Trust assets. In no event will the Trustee be deemed to have acted negligently, fraudulently
or in bad faith if it takes or suffers action in good faith in reliance upon and in accordance with the advice of parties considered to be qualified as experts on the matters submitted to them. The Trustee is not entitled to indemnification from
Unit holders except in certain limited circumstances related to the replacement of mutilated, destroyed, lost or stolen certificates. See Item 1  Description of Units  Liability of Unit Holders. Duration of Trust The Trust is
irrevocable and Pacific (USA) has no power to terminate the Trust or, except with respect to certain corrective amendments, to alter or amend the terms of the Trust Agreement. The Trust will exist until it is terminated by (i) two successive
fiscal years in which the Trusts gross revenues from the Royalty Properties are less than $2,000,000 per year, (ii) a vote of Unit holders as described below under Voting Rights of Unit Holders or (iii) operation of
provisions of the Trust Agreement intended to permit compliance by the Trust with the rule against perpetuities.  3




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Upon the termination of the Trust, the Trustee will continue to act in such capacity until all the
assets of the Trust are distributed. The Trustee will sell all Trust properties for cash (unless the Unit holders authorize the sale for a specified non-cash consideration, in which event the Trustee may, but
is not obligated to, consummate such non-cash sale) in one or more sales and, after satisfying all existing liabilities and establishing adequate reserves for the payment of contingent liabilities, will
distribute all available proceeds to the Unit holders. Voting Rights of Unit Holders Although Unit holders possess certain voting rights, their voting rights are not comparable to those of shareholders of a corporation. For example, there
is no requirement for annual meetings of Unit holders or for annual or other periodic re-election of the Trustee. The Trust Agreement may be amended by the affirmative vote of a majority of the outstanding Units at any duly called meeting of Unit holders. However,
no such amendment may alter the relative rights of Unit holders unless approved by the affirmative vote of 100 percent of the Unit holders and by the Trustee. In addition, certain special voting requirements can be amended only if such
amendment is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee. Removal of the Trustee requires the
affirmative vote of the holders of a majority of the Units represented at a duly called meeting of Unit holders. In the event of a vacancy in the position of Trustee or if the Trustee has given notice of its intention to resign, a successor trustee
of the Trust may be appointed by similar voting approval of the Unit holders. The sale of all or any part of the assets of the Trust must be
authorized by the affirmative vote of the holders of a majority of the outstanding Units. However, the Trustee may, without a vote of the Unit holders, sell all or any part of the Trust assets upon termination of the Trust or otherwise if necessary
to provide for the payment of specific liabilities of the Trust then due. The Trust can be terminated by the Unit holders only if the termination is approved by the holders of a majority of the outstanding Units. Meetings of Unit holders may be called by the Trustee at any time at its discretion and must be called by the Trustee at the written request of holders
of not less than 10 percent of the then outstanding Units. The presence of a majority of the outstanding Units is necessary to constitute a quorum and Unit holders may vote in person or by proxy. Notice of any meeting of Unit holders must be given not more than 60 nor less than 20 days prior to the date of such meeting. The notice must state
the purposes of the meeting and no other matter may be presented or acted upon at the meeting. DESCRIPTION OF UNITS Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the
Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At March 2, 2020, there were 14,579,345 Units outstanding. The Trust may not issue additional Units unless such issuance is approved by the holders of at least 80 percent of the outstanding Units and by the
Trustee. Under limited circumstances, Units may be redeemed by the Trust and canceled. See Possible Divestiture of Units below.  4




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Distributions of Distributable Income The identity of Unit holders entitled to receive distributions of Trust distributable income and the amounts thereof are determined as of each Monthly
Record Date. Unit holders of record as of the Monthly Record Date (the 15th day of each calendar month except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for the related Monthly Period
no later than 10 business days after the Monthly Record Date. The Monthly Income Amount is the excess of (i) revenues from the Trust properties plus any decrease in cash reserves previously established for contingent liabilities and any other
cash receipts of the Trust over (ii) 
the expenses and payments of liabilities of the Trust plus any increase in cash reserves for contingent liabilities. Transfer Units are transferable on the records of the Trustee upon surrender of any certificate in proper form for transfer (or in compliance with the
Trustees procedures for uncertificated Units) and compliance with such reasonable regulations as the Trustee may prescribe. No service charge is made to the transferor or transferee for any transfer of a Unit, but the Trustee may require
payment of a sum sufficient to cover any tax or governmental charge that may be imposed in relation to such transfer. Until any such transfer, the Trustee may conclusively treat the holder of a Unit shown by its records as the owner of that Unit for
all purposes. Any such transfer of a Unit will, as to the Trustee, vest in the transferee all rights of the transferor at the date of transfer, except that the transfer of a Unit after the Monthly Record Date for a distribution will not transfer the
right of the transferor to such distribution. The transfer of Units by gift and the transfer of Units held by a decedents estate, and
distributions from the Trust in respect thereof, may be restricted under applicable state law. American Stock Transfer and Trust Company serves as
the transfer agent and registrar for the Units. Reports to Unit Holders As promptly as practicable following the end of each fiscal year, the Trustee mails to each person who was a Unit holder on any Monthly Record Date
during such fiscal year, a report showing in reasonable detail on a cash basis the receipts and disbursements and income and expenses of the Trust for federal and state tax purposes for each Monthly Period during such fiscal year and containing
sufficient information to enable Unit holders to make all calculations necessary for federal and state tax purposes. As promptly as practicable following the end of each of the first three fiscal quarters of each year, the Trustee mails a report for
such fiscal quarter showing in reasonable detail on a cash basis the assets and liabilities, receipts and disbursements, and income and expenses of the Trust for such fiscal quarter to Unit holders of record on the last Monthly Record Date
immediately preceding the mailing thereof. Within 120 days following the end of each fiscal year, or such shorter period as may be required by the New York Stock Exchange, the Trustee mails to Unit holders of record on the last Monthly
Record Date immediately preceding the mailing thereof, an annual report containing audited financial statements of the Trust and an audited statement of fees and expenses paid by the Trust to the Trustee and escrow agent. See Federal
Taxation below. Each Unit holder and his or her duly authorized agent has the right, during reasonable business hours at his or her own
expense, to examine and make audits of the Trust and the records of the Trustee, including lists of Unit holders, for any proper purpose in reference thereto. Widely Held Fixed Investment Trust Reporting Information Some Trust Units are held by middlemen, as such term is broadly defined
in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in  5




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street name, referred to here in collectively as middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed
investment trust (WHFIT) for U.S. federal income tax purposes. Simmons Bank, EIN 71-0162300, 2911 Turtle Creek Blvd., Ste. 850, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address
trustee@sbr-sabine.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the
Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabine.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for
complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by
middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units. Liability of Unit Holders As regards the Unit holders, the Trustee, in engaging in any activity or transaction that results or could result
in any kind of liability, will be fully liable if the Trustee fails to take reasonable steps necessary to ensure that such liability is satisfiable only out of the Trust assets (even if the assets are inadequate to satisfy the liability) and in no
event out of amounts distributed to, or other assets owned by, Unit holders. However, the Trust might be held to constitute a joint stock company under Texas law, which is unsettled on this point, and therefore a Unit holder may be
jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of both the Trust and the Trustee are not adequate to satisfy such liability.
In view of the substantial value and passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee of the Trust, the imposition of any liability on a Unit
holder is believed to be extremely unlikely. Possible Divestiture of Units The Trust Agreement imposes no restrictions based on nationality or other status of the persons or entities which are eligible to hold Units. However,
the Trust Agreement provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the
nationality, or any other status, of any one or more Unit holders, the following procedure will be applicable: 1. The Trustee
will give written notice to each holder whose nationality or other status is an issue in the proceeding of the existence of such controversy. The notice will contain a reasonable summary of such controversy and will constitute a demand to each such
holder that he or she dispose of his or her Units within 30 days to a party not of the nationality or other status at issue in the proceeding described in the notice. 2. If any holder fails to dispose of his or her Units in accordance with such notice, the Trustee shall have the preemptive right to
redeem and shall redeem, at any time during the 90-day period following the termination of the 30-day period specified in the notice, any Unit not so transferred for a
cash price equal to the closing price of the Units on the stock exchange on which the Units are then listed or, in the absence of any such listing, the mean between the closing bid and asked prices for the Units in the
over-the-counter market, as of the last business day prior to the expiration of the 30-day period stated in the notice. 3. The Trustee shall cancel any Unit acquired in accordance with the foregoing procedures. 4. The Trustee may, in its sole discretion, cause the Trust to borrow any amount required to redeem Units.  6




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FEDERAL TAXATION The tax consequences to a Unit holder of the ownership and sale of units will depend in part on the Unit holders tax circumstances. Each Unit
holder should therefore consult the Unit holders tax advisor about the federal, state and local tax consequences to the Unit holder of the ownership of units. In May 1983, the Internal Revenue Service (the Service) ruled that the Trust is classified as a grantor trust for federal income tax
purposes and not as an association taxable as a corporation. Accordingly, the income and deductions of the Trust are reportable directly by Unit holders for federal income tax purposes. The Service also ruled that Unit holders would be entitled to
deduct cost depletion with respect to their investment in the Trust and that the transfer of a Unit in the Trust would be considered to be a transfer of a proportionate part of the properties held by the Trust. Transferees of Units transferred after October 11, 1990, may be entitled to a percentage depletion deduction attributable to such Units, if the
percentage depletion deduction exceeds cost depletion. Unlike cost depletion, percentage depletion is not limited to a Unit holders depletable tax basis in the Units. Rather, a Unit holder is entitled to a percentage depletion deduction as
long as the applicable Royalty Properties generate gross income. Unit holders should compute both percentage depletion and cost depletion from each property and claim the larger amount as a deduction on their income tax returns. If a taxpayer disposes of any Section 1254 property (certain oil, gas, geothermal or other mineral property), and if the adjusted basis
of such property includes adjustments for depletion deductions under Section 611 of the Internal Revenue Code (the Code), the taxpayer generally must recapture the amount deducted for depletion as ordinary income (to the extent of gain
realized on the disposition of the property). This depletion recapture rule applies to any disposition of Section 1254 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Service could take the position
that a Unit holder who purchases a Unit subsequent to December 31, 1986, must recapture depletion upon the disposition of that Unit. Unit
holders must maintain records of their adjusted basis in their Trust Units (generally his or her cost less prior depletion deductions), make adjustments for depletion deductions to such basis, and use the adjusted basis for the computation of gain
or loss on the disposition of the Trust Units. In order to facilitate the creation of the Trust and to avoid the administrative expense and
inconvenience of daily reporting to Unit holders by the Trustee, the conveyances by Sabine Corporation of the Royalty Properties located in five of the six states (Florida, Mississippi, New Mexico, Oklahoma, and Texas) provided for the execution of
an escrow agreement by Sabine Corporation and InterFirst (the initial trustee of the Trust), in its capacities as trustee of the Trust and as escrow agent. The conveyances by Sabine Corporation of the Royalty Properties located in Louisiana provided
for the execution of a substantially identical escrow agreement by Sabine Corporation and Hibernia National Bank in New Orleans, in the capacities of escrow agent and of trustee of Sabine Louisiana Royalty Trust. The Trust now only has one escrow
agent, which is the Trustee, and a single escrow agreement. Pursuant to the terms of the escrow agreement and the conveyances of the Royalty
Properties, the proceeds of production from the Royalty Properties for each calendar month, and interest thereon, are collected by the escrow agent and are paid to and received by the Trust only on the next Monthly Record Date. The escrow agent has
agreed to endeavor to assure that it incurs and pays expenses and fees for each calendar month only on the next Monthly Record Date. The Trust Agreement also provides that the Trustee is to endeavor to assure that income of the Trust will be accrued
and received and expenses of the Trust will be incurred and paid only on each Monthly Record Date.  7




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Assuming that the escrow arrangement is recognized for federal income tax purposes and that the
Trustee, as escrow agent, is able to control the timing of income and expenses, as stated above, cash and accrual basis Unit holders should be treated as realizing income only on each Monthly Record Date. The Trustee, as escrow agent, may not be
able to cause third party expenses to be incurred on each Monthly Record Date in all instances. Cash basis Unit holders, however, should be treated as having paid all expenses and fees only when such expenses and fees are actually paid by the
Trustee. Even if the escrow arrangement is recognized for federal income tax purposes, however, accrual basis Unit holders might be considered to have accrued expenses when such expenses are incurred rather than on each Monthly Record Date when
paid. No ruling was requested from the Service with respect to the effect of the escrow arrangements when established. Due to the absence of direct
authority and the factual nature of the characterization of the relationship among the escrow agents, Pacific (USA) and the Trust, no opinion was expressed by legal counsel with respect to the tax consequences of the escrow arrangements. If the
escrow arrangement is recognized, the income from the Royalty Properties for a calendar month and interest income thereon will be taxed to the holder of the Unit on the next Monthly Record Date without regard to the ownership of the Unit prior to
that date. The Trustee is treating the escrow arrangement as effective for tax purposes and furnishes tax information to Unit holders on that basis. The Service might take the position that the escrow arrangement should be ignored for federal tax purposes. In such case, the Trustee could be required
to report the proceeds from production and interest income thereon to the Unit holders on a daily basis, in accordance with their method of accounting, as the proceeds from production and interest thereon were received or accrued by the escrow
agent. Such reporting could impact who is taxed on the production and interest income and result in a substantial increase in the administrative expenses of the Trust. In the event of a transfer of a Unit, the income and the depletion deduction
attributable to the Royalty Properties for the period up to the date of transfer would be allocated to the transferor, and the income and depletion deduction attributable to the Royalty Properties on and after the date of transfer would be allocated
to the transferee. Such allocation would be required even though the transferee was the holder of the Unit on the next Monthly Record Date and, therefore, would be entitled to the monthly income distribution. Thus, if the escrow arrangement is not
recognized, a mismatching of the monthly income distribution and the Unit holders taxable income and deductions could occur between a transferor and a transferee upon the transfer of a Unit. Unit holders of record on each Monthly Record Date are entitled to receive monthly distributions. See Description of Units  Distributions of
Net Income above. The terms of the escrow agreement and the Trust Agreement, as described above, seek to assure that taxable income attributable to such distributions will be reported by the Unit holder who receives such distributions,
assuming that such holder is the holder of record on the Monthly Record Date. In certain circumstances, however, a Unit holder may be required to report taxable income attributable to his or her Units but the Unit holder will not receive the
distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy debts and liabilities of the Trust, income used to establish such reserve or to repay such loan will be reported by the Unit
holder, even though such income is not distributed to the Unit holder. Interest and royalty income attributable to ownership of Units and any gain
on the sale thereof are considered portfolio income, and not income from a passive activity, to the extent a Unit holder acquires and holds Units as an investment and not in the ordinary course of a trade or business. Therefore, interest
and royalty income attributable to ownership of Units generally may not be offset by losses from any passive activities. As a result of the 2017
Tax Cuts and Jobs Act (the TCJA), for tax years beginning after December 31, 2017 and before January 1, 2026, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 37%, and the highest marginal
U.S. federal income tax rate applicable to  8




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long-term capital gains (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. Under the TCJA, for
such tax years, personal exemptions and deductions for miscellaneous itemized deductions are not allowed. For such tax years, the U.S. federal income tax rate applicable to corporations is 21%, and such rate applies to both ordinary income and
capital gains. Individuals may incur expenses in connection with the acquisition or maintenance of Trust Units. For tax years beginning before
January 1, 2018, these expenses, which are different from a Unit holders share of the Trusts administrative expenses discussed above, may be deductible as miscellaneous itemized deductions only to the extent that
such expenses exceed 2% of the individuals adjusted gross income. Under the TCJA, for tax years beginning after December 31, 2017 and before January 1, 2026, miscellaneous itemized deductions are not allowed. Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts. For these purposes,
investment income generally will include a Unit holders allocable share of the Trusts interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i)
the individuals net investment income from all investments, or (ii) the amount by which the individuals modified adjusted gross income exceeds specified threshold levels depending on such individuals federal income tax filing
status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income, or (ii) the excess adjusted gross income over the dollar amount at which the highest income tax bracket applicable to an estate
or trust begins. Pursuant to the Foreign Account Tax Compliance Act (commonly referred to as FATCA), distributions from the Trust to
foreign financial institutions and certain other non-financial foreign entities may be subject to U.S. withholding taxes. Specifically, certain withholdable payments (including certain royalties, interest and
other gains or income from U.S. sources) made to a foreign financial institution or non-financial foreign entity will generally be subject to the withholding tax unless the foreign financial institution or non-financial foreign entity complies with
certain information reporting, withholding, identification, certification and related requirements imposed by FATCA. Foreign financial institutions located in jurisdictions that have an intergovernmental agreement with the United States governing
FATCA may be subject to different rules. The Treasury Department issued guidance providing that the FATCA withholding rules described above
generally apply to qualifying payments made after June 30, 2014. Foreign Unit holders are encouraged to consult their own tax advisors regarding the possible implications of these withholding provisions on their investment in Trust Units. The foregoing summary is not exhaustive and does not purport to be complete. Many other provisions of the federal tax laws may affect individual Unit
holders. Each Unit holder should consult his or her personal tax adviser with respect to the effects of his or her ownership of Units on his or her personal tax situation. STATE TAX CONSIDERATIONS The following is intended as a brief summary of certain information regarding state taxes and other state tax matters affecting the trust and the
Unit holders. Unit holders should consult the Unit holders tax advisor regarding state tax filing and compliance matters. Texas.    Texas does not impose an individual income tax. Therefore, no part of the income produced by the Trust is subject
to an individual income tax in Texas. However, Texas imposes a franchise tax at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes.  9




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Entities subject to tax generally include trusts and most other types of entities having limited liability protection, unless otherwise exempt. Trusts that receive at least 90% of their federal
gross income from designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an
active trade or business, are generally exempt from the Texas franchise tax as passive entities. The Trust has been and expects to continue to be exempt from Texas franchise tax as a passive entity. Because the Trust should be exempt
from Texas franchise tax at the Trust level as a passive entity, each Unit holder that is a taxable entity under the Texas franchise tax generally will be required to include its share of Trust revenues in its own Texas franchise tax
computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the location of the
day-to-day operations of the Trust, which is Texas. Louisiana.The Trustee is required to file with Louisiana a return reflecting the income of the Trust attributable to
mineral interests located in Louisiana. Both Louisiana resident and non-resident Unit holders may be subject to the Louisiana personal, corporate and/or franchise tax as certain income and expenses from the
Trust are from sources within Louisiana. Florida, Mississippi, New Mexico and Oklahoma.Florida does not impose an
individual income tax. Florida imposes an income tax on resident and nonresident corporations (except for S corporations not subject to the built-in gains tax or passive investment income tax), which will
apply to royalty income allocable to a corporate Unit holder from properties located within Florida. Mississippi, New Mexico and Oklahoma each impose an income tax applicable to both resident and nonresident individuals and/or corporations (subject
to certain exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes), which will apply to royalty income allocable to a Unit holder from properties located within these states.
Although the Trust may be required to file information returns with taxing authorities in those states and provide copies of such returns to the Unit holders, because the Trust distributes all of its net income to Unit holders, the Trust should not
be taxed at the Trust level in any of these states. The Royalty Properties that are located in such states should be considered economic interests in minerals for state income tax purposes. Generally, the state income tax due by nonresidents in all of the aforementioned states is computed as a percentage of taxable income attributable to
the particular state. By contrast, residents are taxed on their taxable income from all sources, wherever earned. Furthermore, even though state laws vary, taxable income for state purposes is often computed in a manner similar to the computation of
taxable income for federal income tax purposes. Some of these states give credit for taxes paid to other states by their residents on income from sources in those other states. In certain of these states, a Unit holder is required to file a state
income tax return if income is attributable to the Unit holder even though no tax is owed. Both New Mexico and Oklahoma impose a withholding tax on
payments to non residents of oil and gas proceeds derived from royalty interests. To reduce the administrative burden imposed by these rules, the Trustee has opted to allow the payors of oil and gas proceeds to withhold on royalty payments made to
the Trust. The Trust files New Mexico and Oklahoma tax returns, obtains a refund, and distributes that refund to Unit holders. Withholding at the
Trust level reduces the amount of cash available for distribution to Unit holders. Unit holders who transfer their Units before either the New Mexico or Oklahoma tax refunds are received by the Trust or after the refunds are received but before the
next Monthly Record Date will not receive any portion of the refund. As a result, such Unit holders may incur a double tax  first through the reduced distribution received from the Trust and second by the tax payment made directly to New
Mexico or Oklahoma with the filing of their New Mexico or Oklahoma income tax returns.  10




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REGULATION AND PRICES Regulation General Exploration for and production and sale of oil and gas are extensively regulated at the national, state, tribal, and local levels. Oil and gas
development and production activities are subject to federal, tribal, state, and local law, regulations and orders of regulatory bodies pursuant thereto. These laws may govern a wide variety of matters, including allowable rates of production,
transportation, marketing, pricing, well construction, water use, prevention of waste, waste disposal, pollution, and protection of the environment. These laws, regulations and orders have in the past, and may again, restrict the rate of oil and gas
production below the rate that would otherwise exist in the absence of such laws, regulations and orders. Laws affecting the oil and gas industry
and the distribution of its products are under constant review for amendment or expansion, frequently increasing the regulatory burden. Numerous governmental departments and agencies are authorized by statute or other laws to issue, and have issued,
rules and regulations binding on the oil and gas industry which are often difficult and costly to comply with and which impose substantial penalties for the failure to comply. Natural Gas Prices for the sale of natural
gas, like the sale of other commodities, are governed by the marketplace and the provisions of applicable gas sales contracts. The Federal Energy Regulatory Commission (FERC), which principally is responsible for regulating interstate
transportation and the sale of natural gas, has taken significant steps in the implementation of a policy to restructure the natural gas pipeline industry to promote full competition in the sales of natural gas, so that all natural gas suppliers,
including pipelines, can compete equally for sales customers. This policy has been implemented largely through restructuring proceedings and is subject to continuing refinement. The effects of this policy are now presumably fully reflected in the
natural gas markets. The current policy of FERC continues to promote increased competition among gas industry participants. Accordingly, various regulations and orders have been proposed and implemented to encourage nondiscriminatory open-access
transportation by interstate pipelines and to provide for the unbundling of pipeline services so that such services may also be furnished by non-pipeline suppliers on a competitive basis. Many other statutes, rules, regulations and orders affect the pricing or transportation of natural gas. Some of the provisions are and will be subject
to court or administrative review. Consequently, uncertainty as to the ultimate impact of these regulatory provisions on the prices and production of natural gas from the Royalty Properties is expected to continue for the foreseeable future. Environmental Regulation General.Activities on the Royalty Properties are subject to existing stringent and complex federal, tribal, state and
local laws (including case law), rules and regulations governing health, safety, environmental quality and pollution control. Absent the occurrence of an extraordinary event, the cost of compliance with existing federal, tribal, state and local
laws, rules and regulations regulating health; safety; the acquisition of a permit before conducting drilling, production, or underground injection activities; the reporting of the types and quantities of various substances stored, processed,
transported, generated, or released in connection with operation of the Royalty Properties; planning and preparedness for spill and emergency response activities; the limitation or prohibition of drilling activities on certain lands lying within
wilderness, wetlands, endangered or threatened species habitat and other protected areas; the imposition of substantial liabilities for pollution resulting from operations including waste generation, air emissions, water discharges and current and
historical waste disposal practices; the release and associated remediation of  11




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materials in the environment; or otherwise relating to the protection of the environment or human health and safety should not have a material adverse effect upon the Trust or Unit holders.
Failure, however, to comply with these laws, rules and regulations may result in the assessment of administrative, civil or criminal penalties; the imposition of investigatory or remedial obligations; and the issuance of injunctions limiting or
preventing some or all of the operations. Under certain environmental laws and regulations, the operators of the Royalty Properties could also be subject to joint and several, strict liability for the removal or remediation of previously released
materials or property contamination, in either case, whether at a drill site or a waste disposal facility, regardless of whether the operators were responsible for the release or contamination or if the operations were in compliance with all
applicable laws at the time the actions were taken. Superfund.The Comprehensive Environmental Response, Compensation
and Liability Act (CERCLA), also known as the superfund law, imposes liability, regardless of fault or the legality of the conduct at the time it occurred, on certain classes of persons that contributed to the release of a
hazardous substance into the environment. These persons include the current or previous owner and operator of a site where a hazardous substance has been disposed and persons who disposed or arranged for the disposal of a hazardous
substance at a site, or transported a hazardous substance to a site for disposal. CERCLA also authorizes the U.S. Environmental Protection Agency (EPA) and, in some cases, private parties to take actions in response to threats to the
public health or the environment and to seek recovery from such responsible classes of persons of the costs of such an action, including the costs of certain health studies. In the course of operations, the working interest owner and/or the operator
of Royalty Properties may have generated and may generate wastes that may fall within CERCLAs definition of hazardous substances. The operator of the Royalty Properties or the working interest owners may be responsible under CERCLA
for all or part of the costs to clean up sites at which such substances have been disposed. Although the Trust is not the operator of any Royalty Properties, or the owner of any working interest, its ownership of royalty interests could cause it to
be responsible for all or part of such costs to the extent CERCLA imposes responsibility on such parties as owners. Solid and
Hazardous Waste.The Royalty Properties have produced oil and/or gas for many years and, in connection with that production, managed waste, such as drilling fluids and produced water, that is subject to regulation under
environmental laws. Although the Trust has no knowledge of the procedures followed by the operators of the Royalty Properties in this regard, hydrocarbons or other solid or hazardous wastes may have been or may be disposed or released on, under, or
from the Royalty Properties by the current or previous operators or may have been disposed offsite of the Royalty Properties. Federal, state and local laws and regulations applicable to oil and gas-related wastes and properties have generally become
more stringent over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil or criminal penalties, the imposition of investigatory, ongoing monitoring or remedial obligations, and/or the issuance
of injunctions limiting or preventing some or all of the operations. These laws may require not only removal or remediation of current releases of such materials, but also of previously disposed wastes or property contamination at a drill site or a
waste disposal facility, regardless of whether the current owners or operators were responsible for the release or contamination or if the operations were in compliance with all applicable laws at the time of the release or disposal. Disposal Wells The federal Safe Drinking
Water Act (SDWA), the Underground Injection Control (UIC) program promulgated under the SDWA and state programs regulate the drilling and operation of salt water disposal wells. EPA directly administers the UIC program in
some states and in others administration is delegated to the state. Permits must be obtained before drilling salt water disposal wells, and mechanical integrity monitoring must be conducted periodically to ensure that the disposed waters are not
leaking into groundwater. In addition, because some states have become concerned that the injection or disposal of produced water could, under certain circumstances, trigger or contribute to earthquakes, they have adopted or are considering
additional regulations regarding such disposal methods. Changes in regulations or the  12




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inability to obtain permits for new disposal wells in the future may affect the ability of the operators of the Royalty Properties to dispose of produced water and ultimately increase the cost of
operation of the Royalty Properties or delay production schedules. For example, in 2014, the Railroad Commission of Texas (RRC) published a final rule governing permitting or re-permitting of disposal wells that requires, 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 injected 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
RRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. In addition, several cases have
recently put a spotlight on the issue of whether injection wells may be regulated under the Federal Water Pollution Control Act (the Clean Water Act or CWA) if a direct hydrological connection to a jurisdictional surface
water can be established. The split among federal circuit courts of appeals that decided these cases engendered two petitions for writ of certiorari to the United States Supreme Court in August 2018, one of which was granted in February 2019. Oral
arguments were presented to the Supreme Court in November 2019, and the Court is expected to rule sometime in 2020. EPA has also brought attention to the reach of the CWAs jurisdiction in such instances by issuing a request for comment in
February 2018 regarding the applicability of the CWA permitting program to discharges into groundwater with a direct hydrological connection to jurisdictional surface water, which hydrological connections should be considered direct, and
whether such discharges would be better addressed through other federal or state programs. In a statement issued by EPA in April 2019, the Agency concluded that the CWA should not be interpreted to require permits for discharges of pollutants that
reach surface waters via groundwater. But should the Supreme Court rule that CWA permitting be required for saltwater injections wells, the costs associated with operations of the Royalty Properties could increase. Threatened and Endangered Species, Migratory Birds and Natural Resources.Various state and federal statutes
prohibit certain actions that adversely affect endangered or threatened species and their habitat, migratory birds and their habitat, wetlands, and natural resources. These statutes include the Endangered Species Act, the Migratory Bird Treaty Act,
the Bald and Golden Eagle Protection Act, the Clean Water Act, and CERCLA. The United States Fish and Wildlife Service (USFWS) may designate critical habitat and suitable habitat areas that it believes are necessary for the survival of
threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or development. Where takings of, or
harm to, species or damages to wetlands, habitat or natural resources occur or may occur, government entities or at times private parties may act to restrict or prevent oil and gas exploration or production activities or seek damages for harm to
species, habitat or natural resources resulting from drilling or construction or production activities, including, for example, for releases of oil, wastes, hazardous substances or other regulated materials, and may seek natural resources damages
and, in some cases, criminal penalties. Water Discharges.The CWA and analogous state laws impose restrictions and
strict controls on the discharge of pollutants and fill material, including spills and leaks of oil and other substances, into regulated waters, including wetlands. The discharge of pollutants into regulated waters is prohibited, except in
accordance with the terms of a permit issued by the EPA, an analogous state agency, or, in the case of fill material, the United States Army Corps of Engineers. Which waters are considered protected under the CWA, also known as waters of the
United States (WOTUS) has recently been in flux due to recent rulemaking and associated litigation concerning the WOTUS definition. For example, in May 2015, EPA and the U.S. Army Corps of Engineers jointly announced a final rule which would have made additional waters expressly
Waters of the United States and therefore subject to the jurisdiction of the CWA, rather than subject to a case-specific evaluation; the rule was subsequently stayed  13




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by the U.S. Court of Appeals for the Sixth Circuit before it took effect. On February 1, 2018, EPA officially delayed implementation of the 2015 rule until early 2020, and in July 2018, the EPA
proposed repeal of the 2015 WOTUS rule. Later that year, EPAs decision was challenged in court, which resulted in a decision by the U.S. District Court for the District of South Carolina to enjoin EPAs February 2018 delay rule. Several
states then acted to halt reinstatement of the 2015 WOTUS rule, the effect of all of which was that the 2015 WOTUS definition was in effect in 22 states. In September 2019, EPA finalized the repeal of the 2015 WOTUS rule, and the repeal became
effective in December 2019, reinstating the pre-2015 standards. Litigation of the repeal quickly ensued. Meanwhile, in December 2018, the EPA and
the U.S. Army Corps of Engineers issued a proposed rule to revise the definition of Waters of the United States. The rule was finalized in January 2020, and will become effective 60 days after publication in the Federal Register. The
rule narrows the definition, excluding, for example, streams that flow only after precipitation and wetlands without a direct surface connection to other traditional navigable waters. The rule is expected to be heavily litigated, which could delay
its implementation. Regardless, the applicable WOTUS definition affects what CWA permitting or other regulatory obligations may be triggered during development and operation of the Royalty Properties, and changes to the WOTUS definition could cause
delays in development and/or increase the cost of development and operation of the Royalty Properties. Spill prevention, control, and
countermeasure (SPCC) regulations promulgated under the CWA and later amended by the Oil Pollution Act of 1990 impose obligations and liabilities related to the prevention of oil spills and damages resulting from such spills into or
threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities that store oil in more than threshold quantities, the release of which could reasonably be expected to reach
jurisdictional waters, must develop, implement, and maintain SPCC Plans. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the CWA and
analogous state laws and regulations. Climate Change/Hydraulic Fracturing.    Climate change has become the subject of
an important public policy debate and the basis for new legislation proposed by the United States Congress and certain states. Some states have adopted climate change statutes and regulations. The EPA has issued greenhouse gas monitoring and
reporting regulations. Under those rules, since 2012, annual reporting of greenhouse gases has been required for persons operating certain types of industrial operations, including oil and gas production, transmission and storage operations that
emit 25,000 metric tons or more of carbon dioxide equivalent per year. Beyond measuring and reporting, EPA issued an Endangerment
Finding under Section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of future generations. EPA indicated that it will use data collected through the reporting rules to decide whether
to promulgate future greenhouse gas emission limits. In April 2012, EPA issued a final rule that established new source performance standards for volatile organic compounds (VOCs) and sulfur dioxide, an air toxics standard for major
sources of oil and natural gas production, and an air toxics standard for major sources of natural gas transmission and storage. Since January 1, 2015, all hydraulically fractured or refractured natural gas wells must have been completed using so
called green completion technology, which significantly reduces VOC emissions. Limiting emissions of VOCs will have the co-benefit of also limiting methane, a greenhouse gas. These regulations, referred to as New Source Performance
Standards (NSPS) Subpart OOOO, also apply to storage tanks, natural gas wells, and other equipment. In May 2016, EPA issued a suite of new final regulations, referred to as NSPS Subpart OOOOa, designed to limit methane and VOC emissions.
Among other things, these new rules apply green completion requirements to newly fractured and re-fractured oil wells. And rulemaking concerning regulation of greenhouse gas and other emissions from the oil and natural gas industry continues: in
October 2018, the EPA released proposed revisions to some of the NSPS Subpart OOOOa requirements, including reducing the required  14




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frequency of fugitive emissions monitoring at well site and compressor stations. As recently as August 2019, EPA has proposed modifications to the NSPS Subpart OOOO and OOOOa rules  for
example, proposing to remove sources in the transmission and storage segment of the oil and natural gas industry from regulation under NSPS Subpart OOOO/OOOOa and to rescind methane requirements for all production and processing sources in the oil
and natural gas industry or, alternatively, rescind all methane requirements under the rules without removing any sources from the oil and natural gas source category. Accordingly, the ultimate scope of these regulations remains uncertain. In November 2016, the U.S. Department of Interior Bureau of Land Management (BLM) published a final version of its venting and flaring rule,
which imposes stricter reporting obligations and limits venting and flaring of natural gas on federal and Indian lands. Some provisions of the venting and flaring rule went into effect on January 17, 2017. The BLM announced that it would be
postponing until January 17, 2019, the implementation of other aspects of the venting and flaring rule, which were originally scheduled to come into effect on January 17, 2018. In September 2018, however, the BLM announced a final rule that revises
and partially rescinds the 2016 rule. Several of the BLMs recently promulgated rules concerning regulation of oil and gas operations and, in particular, hydraulic fracturing are in various stages of suspension, implementation delay, and court
challenges and, thus, the future of these rules is uncertain. With respect to hydraulic fracturing, in February 2014, the EPA published a final
guidance that broadly defined diesel fuel and which required the issuance of a Class II Underground Injection control permit for hydraulic fracturing treatments using diesel fuel. Those requirements may cause additional costs and delays in hydraulic
fracturing operations using diesel fuels. To the extent diesel fuels are used in hydraulic fracturing activities on properties underlying the Royalty Properties, this guidance will apply. Congress and various states, including Texas, Louisiana, Mississippi, New Mexico and Oklahoma, have proposed or adopted legislation regulating or
requiring disclosure of the chemicals in the hydraulic fracturing fluid that is used in oil and gas drilling operations. Texas, New Mexico and Oklahoma, among other states require oil and gas operators to disclose the chemicals on the Frac Focus
website. On March 20, 2015, the BLM released new regulations governing hydraulic fracturing operations on federal and Indian lands, including
requirements for chemical disclosure, well bore integrity and handling of flowback water. In December of 2017, the BLM repealed the 2015 regulations, and environmental organizations and the State of California sued the BLM and the Secretary of the
U.S. Department of the Interior over the repeal. A hearing on cross-motions for summary judgment in the case was held in the District Court for the Northern District of California in January 2020, and a decision on those motions is currently
pending. The regulations, if reinstated, may result in additional levels of regulation or complexity with respect to existing regulations that could lead to operational delays, increased operating costs and additional regulatory burdens that could
make it more difficult to perform hydraulic fracturing and increase costs of compliance. A number of governmental agencies have conducted studies
on hydraulic fracturing. For example, in 2016 EPA published a final report of a four-year study focused on the possible relationship between hydraulic fracturing and drinking water. In its assessment, EPA concluded that certain aspects of hydraulic
fracturing, such as water withdrawals and wastewater management practices, could result in impacts to water resources, although the report did not identify a direct link between hydraulic fracturing and impacts to groundwater resources. The results
of the study or similar governmental reviews could spur initiatives to further regulate hydraulic fracturing. OSHA and Other Laws and
Regulations.    The Royalty Properties and operation thereof may be subject to the requirements of the federal Occupational Safety and Health Act (OSHA) and comparable state statutes. The OSHA hazard communication
standard, the EPA community right-to-know regulations under Title III of CERCLA, the general duty clause and Risk Management Planning regulations promulgated under  15




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Section 112(r) of the Clean Air Act, and similar state statutes may require disclosure of information about hazardous materials used, produced or otherwise managed during operation of the Royalty
Properties. These laws also require the development of risk management plans for certain facilities to prevent accidental releases of pollutants. The Trustee cannot predict the effect that noncompliance with existing environmental laws, rules and regulations; compliance with new legislation or
regulation, or enforcement policies thereunder; or claims for damages to property, employees, other persons and the environment resulting from operations on the Royalty Properties could have on the Trust or Unit holders. Even if the Trust were not
directly liable for costs or expenses related to these matters, increased costs to achieve compliance with existing or new environmental laws, rules or regulations or to respond to an enforcement action or a private party action could result in
wells being plugged and abandoned earlier in their productive lives, resulting in a loss of reserves and revenues to the Trust. Prices Oil The Trust's average per barrel
oil price decreased from $58.91 in 2018 to $51.44 in 2019. The Trustee believes that the although the OPEC countries continued to curtail production, the U.S. shale boom in 2019 kept a damper on the price of oil. Oil prices remained volatile in 2019
and even with the attacks on the Saudi oil fields, could not overcome the price decrease caused by the record output from U.S. production for more than a few days. Global trade tensions contributed to the volatility in price and helped to keep the
price of oil low during the year. Natural Gas Natural gas prices, which once were determined largely by governmental regulations, are now being governed by the marketplace. Substantial competition in
the natural gas marketplace continues. In addition, competition with alternative fuels persists. The average price received by the Trust in 2019 on natural gas volumes sold of $2.27 per Mcf represented a decrease from the $2.67 per Mcf received in
2018, due largely to continued growth of natural gas production in the U.S. in 2019. The price of natural gas continues to be volatile and the mild weather in early 2020 has continued to put downward pressure on prices. Item 1A.Risk Factors Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors; Lower prices could reduce the net proceeds payable to the Trust and
Trust distributions. The Trusts monthly distributions are highly dependent upon the prices realized from the sale of crude oil and natural
gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unit holders. Crude oil and natural gas prices can fluctuate widely on a
month-to-month basis in response to a variety of factors that are beyond the control of the Trust. Factors that contribute to price fluctuation include, among others:  

political conditions in major oil producing regions, especially in the Middle East;  

worldwide economic conditions;  

weather conditions;  

trade barriers;  

public health concerns;  

the supply and price of domestic and foreign crude oil or natural gas;  

the level of consumer demand;  16




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

the price and availability of alternative fuels;  

the proximity to, and capacity of, transportation facilities;  

the effect of worldwide energy conservation measures; and  

the nature and extent of governmental regulation and taxation. When crude oil and natural gas prices decline, the Trust is affected in two ways. First, distributable income from the Royalty Properties is reduced.
Second, exploration and development activity by operators on the Royalty Properties may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future crude oil and natural gas price
movements, and this reduces the predictability of future cash distributions to Unit holders. Trust reserve estimates depend on many assumptions that may prove
to be inaccurate, which could cause both estimated reserves and estimated future net revenues to be too high, leading to write-downs of estimated reserves. The value of the Units will depend upon, among other things, the reserves attributable to the Royalty Properties. The calculations of proved reserves and
estimating reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon various assumptions regarding future production levels, prices and costs that may prove to be incorrect over time. The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment, and the assumptions used
regarding the quantities of recoverable crude oil and natural gas and the future prices of crude oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include:  

historical production from the area compared with production rates from similar producing areas;  

the effects of governmental regulation;  

assumptions about future commodity prices, production and taxes;  

the availability of enhanced recovery techniques; and  

relationships with landowners, working interest partners, pipeline companies and others. Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trusts estimate of reserves
and future net revenues is further complicated because the Trust holds an interest in net royalties and overriding royalties and does not own a specific percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and
expenditures for the Royalty Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may
require substantial downward revisions or write-downs of reserves. The assets of the Trust are depleting assets and, if the operators developing the Royalty
Properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets.
In addition, a reduction in depletion tax benefits may reduce the market value of the Units. The net proceeds payable to the Trust are derived
from the sale of depleting assets. The reduction in proved reserve quantities is a common measure of depletion. Projects, which are determined solely by the operator, on the Royalty Properties will affect the quantity of proved reserves and can
offset the reduction in proved reserves. If the operators developing the Royalty Properties do not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate
currently expected by the Trust.  17




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Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the
portion of distributions to Unit holders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available
to the Unit holders, which could reduce the market value of the Units over time. Eventually, the Royalty Properties will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds
therefrom. The market price for the Units may not reflect the value of the royalty interests held by the Trust. The public trading price for the Units tends to be tied to the recent and expected levels of cash distribution on the Units. The amounts available for
distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for crude oil and natural gas produced from the Royalty Properties. The market price is not necessarily indicative of the
value that the Trust would realize if it sold those Royalty Properties to a third party buyer. In addition, such market price is not necessarily reflective of the fact that since the assets of the Trust are depleting assets, a portion of each cash
distribution paid on the Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unit holder over the life of these depleting
assets will equal or exceed the purchase price paid by the Unit holder. Terrorism and continued hostilities in the Middle East could decrease Trust
distributions or the market price of the Units. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as
the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, continued hostilities in the Middle East, and other sustained military campaigns could adversely affect Trust distributions or
the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the operators
developing the Royalty Properties rely could be a direct target or an indirect casualty of an act of terror. Future royalty income may be subject to risks
related to the creditworthiness of third parties. The Trusts future royalty income may be subject to risks relating to the
creditworthiness of the operators of the underlying properties and other purchasers of the crude oil and natural gas produced from the underlying properties, as well as risks associated with fluctuations in the price of crude oil and natural gas. Unit holders and the Trustee have no influence over the operations on, or future development of, the Royalty Properties. Neither the Trustee nor the Unit holders can influence or control the operations on, or future development of, the Royalty Properties. The failure of an
operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net
proceeds payable to the Trust. The current operators developing the Royalty Properties are under no obligation to continue operations on the Royalty Properties. Neither the Trustee nor the Unit holders have the right to replace an operator. The operator developing any Royalty Property may abandon the property, thereby terminating the royalties payable to the Trust. The operators developing the Royalty Properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Unit
holders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the royalties relating to the abandoned well or property.  18




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The Royalty Properties can be sold and the Trust would be terminated. The Trustee must sell the Royalty Properties if Unit holders approve the sale or vote to terminate the Trust as described under Item 1 
Description of the Trust  Voting Rights of Unit Holders above. The Trustee must also sell the Royalty Properties if they fail to generate net revenue for the Trust of at least $2,000,000 per year over any consecutive two-year period. Sale of all of the Royalty Properties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders. The sale of the remaining Royalty Properties and the termination
of the Trust will be taxable events to the Trust Unit holders. Generally, a Trust Unit holder will realize gain or loss equal to the difference between the amount realized on the sale and termination of the Trust and his adjusted basis in such
Units. Gain or loss realized by a Trust Unit holder who is not a dealer with respect to such Units and who has a holding period for the Units of more than one year will be treated as long-term capital gain or loss except to the extent of any
depletion recapture amount, which must be treated as ordinary income. Other federal and state tax issues concerning the Trust are discussed under Item 1 and Notes 2 and 9 to the Trusts financial statements, which are included herein. Each
Trust Unit holder should consult his own tax advisor regarding Trust tax compliance matters, including federal and state tax implications concerning the sale of the Royalty Properties and the termination of the Trust. Unit holders have limited voting rights and have limited ability to enforce the Trusts rights against the current or future operators developing the Royalty
Properties. The voting rights of a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no
requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustee. The Trust Agreement and related trust law permit the Trustee and the Trust to take appropriate action against the operators developing the Royalty
Properties to compel them to fulfill the terms of the conveyance of the Royalty Properties. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would likely be limited to bringing
a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit holders probably would not be able to sue any of the operators developing the Royalty Properties. Financial information of the Trust is not prepared in accordance with GAAP. The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than
accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the U.S. Securities and Exchange Commission, the financial statements of the Trust differ from GAAP
financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements. The limited liability of the Unit holders is uncertain. The
Unit holders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporations liabilities. The structure of the Trust does not include the interposition of a limited liability
entity such as a corporation or limited partnership which would provide further limited liability protection to Unit holders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities are to
be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a holder of Units may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually
limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Unit holders may be exposed to personal liability.  19




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The tax treatment of an investment in Trust Units could be affected by recent and potential legislative changes,
possibly on a retroactive basis. U.S. federal tax reform legislation informally known as the Tax Cuts and Jobs Act (the TCJA) was
enacted December 22, 2017, and makes significant changes to the federal income tax rules applicable to both individuals and entities, including changes to the effective tax rate on a Trust Unit holders allocable share of certain income from
the Trust. The TCJA is complex and lacks administrative guidance, thus, Trust Unit holders should consult their tax advisor regarding the TCJA and its effect on an investment in Trust Units. For taxable years beginning after 2017, the highest marginal U.S. federal income tax rates applicable to ordinary income and long-term capital gains of
individuals are 37% and 20%, respectively. Any modification to the U.S. federal income tax laws or interpretations thereof (including administrative guidance relating to the TCJA) may be applied retroactively and could adversely affect our business,
financial condition or results of operations. The Trust is unable to predict whether any changes or other proposals will ultimately be enacted, or whether any adverse interpretations will be used. Any such changes or interpretations could negatively
impact the value of an investment in the Trust Units. Item 1B.Unresolved Staff Comments The Trust has not received any written comments from the Securities and Exchange Commission staff regarding its periodic or current reports under the Act
more than 180 days prior to December 31, 2019, which comments remain unresolved. Item 2.Properties. The assets of the Registrant consist principally of the Royalty Properties, which constitute interests in gross production of
oil, gas and other minerals free of the costs of production. The Royalty Properties consist of royalty and mineral interests, including landowners royalties, overriding royalty interests, minerals (other than executive rights, bonuses and
delay rentals), production payments and any other similar, nonparticipatory interest, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas. These properties are
represented by approximately 5,400 tracts of land. Approximately 2,950 of the tracts are in Oklahoma, 1,750 in Texas, 330 in Louisiana, 200 in New Mexico, 150 in Mississippi and 12 in Florida. The following table summarizes total developed and proved undeveloped acreage represented by the Royalty Properties at December 31, 2019.  Mineral and RoyaltyState

Gross Acres


Net AcresFlorida


5,448



697Louisiana


244,391



23,682Mississippi


75,489



9,713New Mexico


112,294



9,141Oklahoma


381,538



67,558Texas


1,273,132



105,760Total


2,092,292



216,551 Detailed information concerning the number of wells on royalty properties is not generally available to the owner of
royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Royalty Properties, the number of exploratory
or development wells drilled on the Royalty  20




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Properties during the periods presented by this report, or the number of wells in process or other present activities on the Royalty Properties, and the Registrant cannot readily obtain such
information. Title The
conveyances of the Royalty Properties to the Trust covered the royalty and mineral properties located in the six states that were vested in Sabine Corporation on the effective date of the conveyances and that were subject to existing oil, gas and
other mineral leases other than properties specifically excluded in the conveyances. Since Sabine Corporation may not have had available to it as a royalty owner information as to whether specific lands in which it owned a royalty interest were
subject to an existing lease, minimal amounts of nonproducing royalty properties may also have been conveyed to the Trust. Sabine Corporation did not warrant title to the Royalty Properties either expressly or by implication. Reserves The Registrant has
obtained from DeGolyer and MacNaughton, independent petroleum engineering consultants, a study of the proved oil and gas reserves attributable as of January 1, 2020 to the Royalty Properties. The following letter report summarizes such reserve
study and sets forth information as to the assumptions, qualifications, procedures and other matters relating to such reserve study. Because the only assets of the Trust are the Royalty Properties, the Trustee believes the reserve study provides
useful information for Unit holders. There are many uncertainties inherent in estimating quantities and values of proved reserves and in projecting future rates of production. The reserve data set forth herein, although prepared by independent
petroleum engineers in a manner customary in the industry, are estimates only, and actual quantities and values of oil and gas are likely to differ from the estimated amounts set forth herein. In addition, the reserve estimates for the Royalty
Properties will be affected by future changes in sales prices for oil and gas produced. See Note 8 of the Notes to Financial Statements in Item 8 hereof for additional unaudited information regarding the proved oil and gas reserves of the
Trust. Other than those filed with the SEC, our estimated reserves have not been filed with or included in any reports to any federal agency. The
process of estimating oil and gas reserves is complex and requires significant judgment. As a result, the Trustee has developed internal policies and controls for estimating reserves attributable to the Trust. As described above, the Trust does not
have information that would be available to a company with oil and gas operations because detailed information is not generally available to owners of royalty interests. The Trustee gathers production information (which information is net to the
Trusts interests in the Royalty Properties) and provides such information to DeGolyer and MacNaughton, who extrapolates from such information estimates of the reserves attributable to the Royalty Properties based on its expertise in the oil
and gas fields where the Royalty Properties are situated, as well as publicly available information. The Trusts policies regarding reserve estimates require proved reserves to be in compliance with the SEC definitions and guidance. DeGolyer and MacNaughton, the independent petroleum engineering consultants who prepared the reserve study, have provided petroleum consulting services
for more than 70 years. Gregory K. Graves, Senior Vice President with DeGolyer and MacNaughton, was the primary engineer responsible for the report. Mr. Graves qualifications are set forth in the Certificate of Qualification attached to
the letter report below.  21




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DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 February 21, 2020 Simmons Bank 2911 Turtle Creek Blvd, Suite 850 Dallas, Texas 75219-6291 Ladies and Gentlemen: Pursuant to the request of Sabine Royalty Trust (the Trust), this report of third party presents an independent evaluation, as of January 1, 2020,
of the extent and value of the estimated net proved developed producing oil, condensate, natural gas liquids (NGL), and gas reserves of certain properties in which the Trust has represented it holds an interest. This evaluation was completed on
February 21, 2020. The properties evaluated herein consist of royalties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas. Simmons Bank acts as trustee of the Trust. Simmons Bank has represented that these properties
account for 100 percent of revenues attributed to royalty interest payments received by the Trust as of January 1, 2020. The net proved developed producing reserves estimates have been prepared in accordance with the reserves definitions
of Rules 410(a) (1)(32) of Regulation SX of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation SK and is to be
used for inclusion in certain SEC filings by the Trust. Reserves estimates included herein are expressed as net reserves. Gross reserves are
defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests held by the Trust after deducting all
interests held by others. Values for proved developed producing reserves in this report are expressed in terms of future gross revenue, future net
revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad
valorem taxes, and transportation expenses from future gross revenue. Transportation expenses include marketing, processing, and other expenses that are charged to the royalty interests. At the request of the Trust, future income taxes were not
taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a nominal discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth
should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold. Estimates of reserves and revenue should be regarded only as estimates that may change as production history and additional information become
available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in the preparation of this report was obtained on behalf of the Trust from Simmons Bank and from public sources. Additionally, this
information includes data supplied by IHS Markit Inc; Copyright 2019 IHS Markit Inc. In the preparation of this report we have relied, without independent verification, upon information furnished by Simmons Bank with respect to the property
interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and
data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.  22




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Definition of Reserves Petroleum reserves included in this report are classified as proved developed producing. Only proved developed producing reserves have been evaluated for
this report. Producing reserves are those developed reserves expected to be recovered from completion intervals that are open and producing at the time of the estimate. Reserves classifications used in this report are in accordance with the reserves
definitions of Rules 410(a) (1)(32) of Regulation SX of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of
current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating
conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The
petroleum reserves are classified as follows: Proved oil and gas reserves  Proved oil and gas reserves are those quantities of oil and
gas, which, 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 the
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. (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with
reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well
penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii)
Where direct observation from well penetrations has defined a highest known oil (HKO) 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. (iv) Reserves which can
be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) 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 (B) The project has
been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include
prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the
report, determined as an unweighted arithmetic average of the first-day-of-the-month
price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.  23




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Developed oil and gas reserves  Developed oil and gas reserves are 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. Undeveloped oil and gas reserves Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when
drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii)
Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other
improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.410 (a) Definitions], or by other evidence using
reliable technology establishing reasonable certainty. Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in
accordance with the reserves definitions of Rules 410(a) (1)(32) of Regulation SX of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers
entitled Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019. The method or combination of methods used in the analysis of each
reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by the Trust, and analyses of areas offsetting
existing wells with test or production data, reserves were classified as proved developed producing. For depletion-type reservoirs or those whose
performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In the analyses of production-decline
curves, reserves were estimated only to the limits of economic production as defined under the Definition of Reserves heading of this report. Because the Trust is unable to provide actual operating expenses for the properties evaluated (since the
Trusts interests are only royalty interests), typical operating expenses, based on our knowledge of the area and/or field operations, were used to determine the economic limits of production. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were
available. Data provided by the Trust from wells drilled through December 31, 2019, and made available for this evaluation were used to
prepare the reserves estimates herein. These reserves estimates were based on  24




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consideration of monthly production data available for certain properties only through September 2019. Estimated cumulative production, as of January 1, 2020, was deducted from the estimated
gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 3 months. Oil and condensate reserves
estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and liquefied petroleum gas (LPG), which consists
primarily of propane and butane fractions, and are the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In
these estimates 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the
point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas reserves are expressed at a temperature base of 60 degrees
Fahrenheit (°F) and at the pressure base of the state in which the reserves are located. Gas reserves included in this report are expressed in millions of cubic feet (MMcf). Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions
with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication
with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas. The Trust has represented that it holds several thousand individual royalty interests. In view of the small reserves volumes attributable to many of
these individual interests, certain of the reserves representing approximately 38 percent of the total net reserves of the properties included herein were summarized by state or area and estimated in the aggregate rather than on a property-by-property basis. Historical records of net production and revenue and our general knowledge of producing characteristics in the areas involved were used in
evaluating these grouped properties. Primary Economic Assumptions Revenue values in this report were estimated using initial prices, expenses, and costs provided by Simmons Bank. Future prices were estimated using
guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein: Oil, Condensate, and NGL Prices The oil,
condensate, and NGL prices were based on a reference price, calculated as the unweighted arithmetic average of the
first-day-of-the-month price for each month within the
12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Differentials to a West Texas Intermediate oil reference price of $55.85 per barrel were based on
royalty receipts received by the Trust, as provided by Simmons Bank. The prices were held constant thereafter. The volume-weighted average prices attributable to the estimated proved developed producing reserves over the lives of the properties were
$51.71 per barrel of oil and condensate and $16.77 per barrel of NGL. Gas Prices The gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end
of the  25




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reporting period, unless prices are defined by contractual agreements. Differentials to the Henry Hub gas reference price of $2.62 per million Btu were based on royalty receipts received by the
Trust, as provided by Simmons Bank. The prices were held constant thereafter. Btu factors provided by Simmons Bank were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The
volume-weighted average price attributable to the estimated proved developed producing reserves over the lives of the properties was $2.106 per thousand cubic feet of gas. Production and Ad Valorem Taxes Production
taxes were calculated using rates provided by Simmons Bank, including, where appropriate, abatements for enhanced recovery programs. Ad valorem taxes were calculated using rates provided by Simmons Bank based on recent payments by the Trust. Operating Expenses, Capital Costs, and Abandonment Costs The properties evaluated are royalties. Therefore, no operating expenses, capital costs, or abandonment costs are incurred. Because the Trust is unable
to provide actual operating expenses for the properties evaluated, typical operating expenses, based on our knowledge of the area and/or field operations, were used to determine the economic limits of production. Several properties incur additional expenses related to transportation, marketing, processing, and other expenses that are charged to the royalty
interests. These expenses are reported as transportation expenses. These expenses were not adjusted for inflation. In our opinion, the information
relating to estimated proved developed producing reserves, estimated future net revenue from proved developed producing reserves, and present worth of estimated future net revenue from proved developed producing reserves of oil, condensate, NGL, and
gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9,
932-235-50-30, and
932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries  Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 410(a) (1)(32) of Regulation SX
and Rules 302(b), 1201, and 1202(a) (1), (2), (3), (4), (8) of Regulation SK of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth
values set forth herein and (ii) estimates of the proved developed producing reserves are not presented at the beginning of the year. To the extent
the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith
or sufficient therefor.  26




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Summary of Conclusions The estimated net proved developed producing reserves, as of January 1, 2020, of the properties evaluated herein were based on the definition of
proved developed reserves of the SEC and are summarized by state as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):  Estimated by DeGolyer and MacNaughtonNet Proved Developed Producing Reservesas of January 1, 2020State

Oil andCondensate(Mbbl)


NGL(Mbbl)


TotalLiquids(Mbbl)


SalesGas(MMcf)Florida


57



4



61



0Louisiana


31



1



32



217Mississippi


72



0



72



388New Mexico


262



107



369



1,469Oklahoma


620



117



737



10,484Texas


4,128



1,664



5,792



22,863Total


5,170



1,893



7,063



35,421 The estimated future revenue to be derived from the production and sale of the net proved developed producing reserves,
as of January 1, 2020, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):  ProvedDevelopedProducing(M$)Future Gross Revenue


373,677Production Taxes


18,782Ad Valorem Taxes


15,072Transportation Expenses


17,697Future Net Revenue


322,126Present Worth at 10 Percent


158,710 Note: Future income taxes have not been taken into account in the preparation of these estimates. While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry
participants ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2020, estimated reserves.  27




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DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been
providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in the Trust. Our fees were not contingent on the results of our evaluation. This
report has been prepared at the request of the Trust. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/
DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716  /s/ Gregory K. GravesGregory K. Graves, P.E.[SEAL]



Senior Vice PresidentDeGolyer and MacNaughton  28




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CERTIFICATE of QUALIFICATION I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A.,
hereby certify:  1.
That I am a Senior Vice President with DeGolyer and MacNaughton, which company did prepare the report of third party
addressed to Simmons Bank dated February 21, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.  2.
That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum
Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of
experience in oil and gas reservoir studies and reserves evaluations.  /s/ Gregory K. GravesGregory K. Graves, P.E.[SEAL]



Senior Vice PresidentDeGolyer and MacNaughton  29




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There are numerous uncertainties inherent in estimating quantities of proved reserves and in
projecting the future rates of production and timing of development. The preceding reserve data in the letter regarding the study represent estimates only and should not be construed to be exact. The estimated present worth of future net revenue
amounts shown by the study should not be construed as the current fair market value of the estimated oil and gas reserves since a market value determination would include many additional factors. Reserve estimates may be adjusted from time to time as more accurate information on the volume or recoverability of existing reserves becomes available.
Actual reserve quantities do not change, however, except through production. The Trust continues to own only the Royalty Properties that were initially transferred to the Trust at the time of its creation and is prohibited by the Trust Agreement
from acquiring additional oil and gas interests. The future net revenue shown by the study has not been reduced for administrative costs and
expenses of the Trust in future years. The costs and expenses of the Trust may increase in future years, depending on the amount of income from the Royalty Properties, increases in the Trustees fees (including escrow agent fees) and expenses,
accounting, engineering, legal and other professional fees, and other factors. It is expected that the costs and expenses of the Trust in 2020 will be approximately $3,000,000. The present value of future net revenue of the Trusts proved developed reserves decreased from $190,325,591 at January 1, 2019 to $158,709,976 at
January 1, 2020. This decrease resulted primarily from the commodity prices used in the calculation of such amount, from an average price of $60.43 per barrel of oil, $21.23 per barrel of NGL and $2.80 per Mcf of gas at January 1, 2019 to an average
price of $51.71 per barrel of oil, $16.77 per barrel of NGL and $2.106 per Mcf of gas at January 1, 2020. Subsequent to year end, the price of both
oil and gas continued to fluctuate, giving rise to a correlating adjustment of the respective standardized measure of discounted future net cash flows. As of February 10, 2020, NYMEX posted oil prices were approximately $49.59 per barrel, which
compared to the average posted price of $55.85 per barrel, used to calculate the worth of future net revenue of the Trusts proved developed reserves, would result in a decrease in the standardized measure of discounted future net cash flows
for oil. As of February 10, 2020, NYMEX posted gas prices were $1.85 per million British thermal units. The use of such price, as compared to the average posted price of $2.62 per million British thermal units, used to calculate the future net
revenue for the Trusts proved developed reserves would result in a decrease in the standardized measure of discounted future net cash flows for gas. The volatile nature of the world energy markets makes it difficult to estimate future prices of oil and gas. The prices obtained for oil and gas depend
upon numerous factors, none of which is within the Trustees control, including the domestic and foreign supply of oil and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of
pipeline capacity, instability in oil-producing regions and the effect of governmental regulations. Item 3.Legal Proceedings. There are no material pending legal proceedings to which the Registrant is a party or
of which any of its property is the subject. Item 4.Mine Safety Disclosures. Not applicable.  30




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##### Table of Contents

PART II  Item 5.
Market for Registrants Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities. The Units are listed and traded on the New York Stock Exchange under the symbol SBR. At February 19, 2020, there were 14,579,345 Units outstanding and approximately 1,019 Unit holders of record. The Trust does not maintain any equity compensation plans. The Trust did not repurchase any Units during the period covered by this report. Item 6.Selected Financial Data.  Years Ended December 31

2019


2018


2017


2016


2015Royalty Income

$
46,726,948


$
52,386,070


$
37,162,911


$
30,022,292


$
48,386,010Distributable Income


44,035,987



49,929,702



34,729,057



27,475,994



45,964,673Distributable Income per Unit


3.02



3.42



2.38



1.88



3.15Total Assets at Year End


6,911,788



9,464,382



5,330,266



5,234,447



6,113,447Distributions per Unit


3.02



3.35



2.37



1.93



3.11 Item 7.Trustees Discussion and Analysis of Financial Condition and Results of
Operations. Liquidity and Capital Resources Sabine Royalty Trust (the Trust) makes monthly distributions to its Unit holders of the excess of the preceding months revenues
received over expenses incurred. Upon receipt, royalty income is invested in short-term investments until its subsequent distribution. In accordance with the Trust Agreement, the Trusts only long-term assets consist of royalty interests in
producing oil and gas properties. Although the Trust is permitted to borrow funds if necessary to continue its operations, borrowings are not anticipated in the foreseeable future. Accordingly the Trust is dependent on its operations to generate
excess cash flows utilized in making distributions. These operating cash flows are largely dependent on such factors as oil and gas prices and production volumes, which are influenced by many factors beyond the control of the Trust. As a royalty
owner, the Trust does not have access to certain types of information that would be disclosed by a company with oil and gas operations. See Item 2. Properties for a discussion of the types of information not available to the Trust. The amount to be distributed to Unit holders (Monthly Income Amount) is determined on a monthly basis. The Monthly Income Amount is an
amount equal to the sum of cash received by the Trust during a monthly period (the period commencing on the day after a monthly record date and continuing through and including the next succeeding monthly record date) attributable to the Royalty
Properties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. Unit holders of record as of the monthly record date (the
15th day of each calendar month, except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for such month on or before 10 business days after the monthly record date. The Monthly Income
Amount per Unit is declared by the Trust no later than 10 days prior to the monthly record date. The cash received by the Trust is primarily from purchasers of the Trusts oil and gas production and consists of gross sales of production
less applicable severance taxes.  31




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##### Table of Contents

Results of Operations Distributable income consists of royalty income plus interest income plus any decrease in cash reserves established by the Trustee less general and
administrative expenses of the Trust less any increase in cash reserves established by the Trustee. The Trusts royalty income represents payments received during a particular time period for oil and gas production from the Trusts
properties. Because of various factors which influence the timing of the Trusts receipt of payments, royalty income for any particular time period will usually include payments for oil and gas produced in prior periods. The price and volume
figures that follow represent the volumes and prices for which the Trust received payment during 2017, 2018, and 2019. Royalty income during 2019
decreased approximately $5,659,000, or 10.8 percent, compared to 2018 royalty income, which had increased approximately $15,223,000, or 41.0 percent, from 2017 royalty income. Revenues generated by sales of oil and gas decreased in 2019 from 2018 as a result of decreased oil and gas prices ($8.0 million); offset somewhat by
higher natural gas and oil production volumes ($1.2 million), and lower expenses, taxes and revenue due others ($1.1 million). Gas volumes
increased from 7,138,837 thousand cubic feet (Mcf) in 2018 to 7,516,325 Mcf in 2019 after increasing from 5,681,137 Mcf in 2017. The average price per Mcf of gas received by the Trust decreased from $2.67 in 2018 to $2.27 in 2019 after
decreasing from $2.95 in 2017. A warmer-than-normal summer and colder weather late in the year led to gas prices increasing somewhat in 2017. Prices continued to stay somewhat higher during the first half of 2018, but an active hurricane season on
the east coast and in the Gulf of Mexico led to decreased demand and, consequently, lower prices for the second half of 2018. Continued robust production in the U.S. led to sustained high inventories which kept the price of natural gas low
throughout 2019. Oil volumes sold increased to 697,089 barrels (Bbls) in 2019 from 689,799 Bbls in 2018 after increasing from 553,558
Bbls in 2017. The average sales price of oil decreased to $51.44 per Bbl in 2019, from $58.91 per Bbl in 2018 after increasing from $46.81 per Bbl in 2017. This increase in the price of oil in 2017 was caused by the economy stabilizing and the
industrial increase in demand. In 2018, oil prices remained on a mostly upward trend. Beginning with the fourth quarter of 2018, however, oil prices decreased significantly. The downward pressure on oil prices continued in 2019 due mainly to the
shale oil production boom that continues. Geopolitical tensions in the Middle East during the latter part of 2019 only caused a temporary increase in oil prices. Interest income was approximately $166,000 in 2019, which had increased from approximately $142,000 in 2018, which had increased from approximately
$41,000 in 2017. Changes in interest income are the result of changes in interest rates and funds available for investment. General and
administrative expenses increased to approximately $2,857,000 in 2019 from approximately $2,599,000 in 2018 due mainly to increases in Escrow Agent/Trustee fees of approximately $162,000; legal and professional expenses of approximately $71,500; and
revenue processing services of approximately $47,300. These increases were offset somewhat by a decrease in Unit holder and printing expenses of approximately $22,200. General and administrative expenses increased to approximately $2,599,000 in 2018 from approximately $2,474,000 in 2017 due mainly to increases in
Escrow Agent/Trustee fees of approximately $74,600; legal and professional expenses of approximately $24,700; printing and Unit holder information services of approximately $18,700; and revenue processing services of approximately $7,400. The cash received by the Trust is primarily from purchasers of the Trusts oil and gas production and consists of gross sales of production less
applicable severance taxes. In January 2019, the Trust received  32




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##### Table of Contents

refunds of $309,879 (tax year 2015) from the State of Oklahoma and $140,474 (tax year 2015) from the State of New Mexico. In March 2019, the Trust received a refund of $334,624 (tax year 2017)
from the State of Oklahoma. In December 2019, the Trust received a refund of $86,535 from the State of New Mexico (tax year 2017). In July 2017, the Trust received a refund of $288,521 (tax year 2016) from the State of Oklahoma and in August 2017,
the Trust received a refund of $88,225 (tax year 2016) from the State of New Mexico. These refunds represented taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and State of
New Mexico by the applicable payors of such proceeds. Income taxes are not payable by the Trust, but are the responsibility of the individual Unit holders. Therefore, the State of Oklahoma and the State of New Mexico refunded the withheld taxes, and
the refunds were included as royalty income in the Trusts February 2019, April 2019, January 2020, August 2017 and September 2017 distributions, respectively. The Trust did file tax returns for 2017 and 2018 with the States of Oklahoma and New Mexico requesting refunds. The Trust will file tax returns for 2019
with the States of Oklahoma and New Mexico requesting refunds. The refunds represent taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and the State of New Mexico by the
applicable payors of such proceeds. Contractual Obligations  Contractual Obligations

Total


Lessthan1 Year


1-3Years


3-5Years


Morethan5 YearsLong-term Debt Obligations


0



0



0



0



0Capital Lease Obligations


0



0



0



0



0Operating Lease Obligations


0



0



0



0



0Purchase Obligations


0



0



0



0



0Other Long-Term Liabilities Reflected on the Trust Balance Sheet


0



0



0



0



0Total


0



0



0



0



0 Critical Accounting Policies and Estimates The Trusts financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates
and assumptions. The following are some of the more critical judgement areas in the application of accounting policies that currently affect the Trusts financial condition and results of operations. 1. Basis of Accounting The financial statements of the Trust
are prepared on the following basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America:  

Royalty income, net of severance and ad valorem taxes, and interest income are recognized in the month in which amounts are
received by either the escrow agent or the Trust, pending verification of ownership and title.  

Trust expenses, consisting principally of routine general and administrative costs, include payments made during the
accounting period. Expenses are accrued to the extent of amounts that become payable on the next monthly record date following the end of the accounting period. Reserves for liabilities that are contingent or uncertain in amount may also be
established if considered necessary.  

Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.  

Distributions to Unit holders are recognized when declared by the Trustee.  33




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##### Table of Contents

The financial statements of the Trust differ from financial statements prepared in conformity with
accounting principles generally accepted in the United States of America because of the following:  

Royalty income is recognized in the month received, pending verification of ownership and title, rather than in the month
of production.  

Expenses other than those expected to be paid on the following monthly record date are not accrued.  

Amortization of the royalties is shown as a reduction to Trust corpus and not as a charge to operating results.  

Reserves may be established for contingencies that would not be recorded under accounting principles generally accepted in
the United States of America. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for
royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. 2.
Revenue Recognition Revenues from royalty interests are recognized in the period in which amounts are received and verified by the Trust or
escrow agent. Royalty income received by the Trust or escrow agent in a given calendar year will generally reflect the proceeds, on an entitlements basis, from natural gas produced for the twelve-month period ended September 30th in that
calendar year and from oil produced for the twelve-month period ended October 31st in the same calendar year. 3. Reserve Disclosure The SEC and the Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of
discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are computed by applying the average prices during the 12-month period prior to
the fiscal year-end, 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. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net
cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in
projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually
recovered and the timing of production may be substantially different from the reserve estimates. See Note 8 of the Notes to Financial Statements in Item 8 hereof for additional information regarding the proved oil and gas reserves of the
Trust. Other than those filed with the SEC, our estimated reserves have not been filed with or included in any reports to any federal agency. 4. Contingencies Contingencies related to the Royalty Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future
royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders. The Trustee is aware of no such items as of December 31, 2019. New Accounting Pronouncements There are no new
pronouncements that are expected to have a significant impact on the Trusts financial statements.  34




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##### Table of Contents

Off-Balance Sheet Arrangements As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility
relating to the operation of the Royalty Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses, and its actions have been limited to those activities. Therefore, the
Trust has not engaged in any off-balance sheet arrangements. Inflation Prices obtained for oil and gas production depend upon numerous factors that are beyond the control of the Trust, including the extent of domestic and
foreign production, imports of foreign oil, market demand, domestic and worldwide economic and political conditions, storage capacity and government regulations and tax laws. Prices for both oil and gas have fluctuated between 2017 and 2019. The
following table presents the weighted average prices received per year by the Trust:  OilPer BBL


GasPer Mcf2019

$
51.44


$
2.272018


58.91



2.672017


46.81



2.95 Forward-Looking Statements This Annual Report includes forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, which
are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the
price of oil and natural gas contained in Item 1, Business, certain reserve information and other statements contained in Item 2, Properties, certain statements regarding the Trusts financial position,
industry conditions and other matters contained in this Item 7 and the satisfaction or waiver of conditions to the Trustees resignation contained in Item 1, Business. Although the Trustee believes that the expectations
reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the
Trustees control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report affecting oil and gas prices (including, without limitation, the domestic and foreign supply of oil
and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of pipeline capacity, instability in oil-producing regions and the effect of
governmental regulations), the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in
Item 1A, Risk Factors. Item 7A.Quantitative and Qualitative Disclosures About Market Risk. The Trust is a passive entity, and other than the Trusts ability to periodically borrow money as necessary to pay expenses,
liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust
periodically holds short term investments acquired with funds held by the Trust pending distribution to Unit holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings
and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign
currencies which could expose the Trust or Unit holders to any foreign currency related market risk. The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments.  35




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##### Table of Contents

Item 8.Financial Statements and Supplementary Data. Report of Independent Registered Public Accounting Firm To
the Unit Holders of Sabine Royalty Trust and Simmons Bank, Trustee Opinion on the Financial Statements We have audited the
accompanying statements of assets, liabilities and trust corpus of Sabine Royalty Trust (the Trust) as of December 31, 2019 and 2018, and the related statements of distributable income and changes in trust corpus for each of the three years in the
period ended December 31, 2019, and the related notes (collectively referred to as the financial statements). In our opinion, the financial statements present fairly, in all material respects, the assets, liabilities, and trust corpus of
the Trust as of December 31, 2019 and 2018, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2019, in conformity with the modified cash basis of accounting, which is a
comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. We also have audited, in
accordance with the standards of the Public Company Accounting Oversight Board (United States), the Trusts internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control  Integrated
Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated March 2, 2020 expressed an unqualified opinion thereon. As described in Note 2 to the financial statements, these financial statements were prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. Basis for Opinion These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these 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 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. 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 the Trustee, as well as evaluating the overall presentation of the financial statements. We
believe that our audits provide a reasonable basis for our opinion. Critical Audit Matters Critical audit matters 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: (1) relate to accounts  36




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##### Table of Contents

or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters. /s/ WEAVER AND TIDWELL, L.L.P. We have served as the Trusts auditor
since 2016. Dallas, Texas March 2, 2020  37




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##### Table of Contents

SABINE ROYALTY TRUST FINANCIAL STATEMENTS Statements of Assets,
Liabilities and Trust Corpus  December 31,2019


2018AssetsCash and short-term investments

$
6,725,823


$
9,250,494Royalty interests in oil and gas properties less accumulated amortization of $22,209,220 (2019) and
$22,181,297 (2018)


185,965



213,888Total

$
6,911,788


$
9,464,382Liabilities and Trust CorpusTrust expenses payable

$
175,843


$
165,216Other payables (Note 4)


1,088,182



3,632,901Total liabilities


1,264,025



3,798,117Contingencies (Note 2)Trust Corpus (14,579,345 units of beneficial interest authorized and outstanding)


5,647,763



5,666,265Total

$
6,911,788


$
9,464,382 Statements of Distributable Income  Year Ended December 31,2019


2018


2017Royalty Income

$
46,726,948


$
52,386,070


$
37,162,911Interest Income


166,481



142,289



40,514Total


46,893,429



52,528,359



37,203,425General and administrative expenses (Note 6)


2,857,442



2,598,657



2,474,368Distributable income

$
44,035,987


$
49,929,702


$
34,729,057Distributable income per unit (Basic and Assuming Dilution) (14,579,345 units) (Notes 1,2)

$
3.02


$
3.42


$
2.38 Statements of Changes in Trust Corpus  2019


2018


2017Trust corpus, beginning of year

$
5,666,265


$
4,594,384


$
4,423,299Amortization of royalty interests


(27,923
)


(30,717
)


(28,685
)Distributable income


44,035,987



49,929,702



34,729,057Distributions to unit holders (Note 3)


(44,026,566
)


(48,827,104
)


(34,529,287
)Trust corpus, end of year

$
5,647,763


$
5,666,265


$
4,594,384Distributions per unit (Note 3)

$
3.02


$
3.35


$
2.37  The accompanying notes are an integral part of these
financial statements.  38




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS 1. Trust Organization and
Provisions Sabine Royalty Trust (the Trust) was established by the Sabine Corporation Royalty Trust Agreement (the Trust
Agreement), made and entered into effective as of December 31, 1982, to receive a distribution from Sabine Corporation (Sabine) of royalty and mineral interests, including landowners royalties, overriding royalty
interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interest, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana,
Mississippi, New Mexico, Oklahoma and Texas (the Royalty Properties). Certificates evidencing units of beneficial interest (the
Units) in the Trust were mailed on December 31, 1982 to Sabines shareholders of record on December 23, 1982, on the basis of one Unit for each share of Sabines outstanding common stock. In May 1988, Sabine was
acquired by Pacific Enterprises, a California corporation. Through a series of mergers, Sabine was merged into Pacific Enterprises Oil Company (USA) (Pacific (USA)), a California corporation and a wholly owned subsidiary of Pacific
Enterprises, effective January 1, 1990. This acquisition and the subsequent mergers had no effect on the Units. Pacific (USA), as successor to Sabine, has assumed by operation of law all of Sabines rights and obligations with respect to
the Trust. The Units are listed and traded on the New York Stock Exchange. In connection with the transfer of the Royalty Properties to the Trust
upon its formation, Sabine had reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. In January 1993, Pacific (USA) completed the sale of substantially all its producing oil and
gas assets to a third party. The sale did not include executive rights relating to the Royalty Properties, and Pacific (USA)s ownership of such rights was not affected by the sale. The wells on the properties conveyed to the Trust are operated by many companies including large, established companies such as BP Amoco, Chevron,
ConocoPhillips and ExxonMobil. The Trustee believes these operators utilize the recovery methods best suited for the particular formations on which the properties are located. Simmons Bank (the Trustee), acts as trustee of the Trust. The terms of the Trust Agreement provide, among other things, that:  

The Trust shall not engage in any business or commercial activity of any kind or acquire assets other than those initially
transferred to the Trust.  

The Trustee may not sell all or any part of its assets unless approved by the holders of a majority of the outstanding
Units in which case the sale must be for cash and the proceeds, after satisfying all existing liabilities, promptly distributed to Unit holders.  

The Trustee may establish a cash reserve for the payment of any liability that is contingent or uncertain in amount or that
otherwise is not currently due and payable.  

The Trustee will use reasonable efforts to cause the Trust and the Unit holders to recognize income and expenses on monthly
record dates.  

The Trustee is authorized to borrow funds to pay liabilities of the Trust provided that such borrowings are repaid in full
before any further distributions are made to Unit holders.  

The Trustee will make monthly cash distributions to Unit holders of record on the monthly record date (see Note 3).  39




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  On January 9, 2014, Bank of America, N.A. (as successor to InterFirst Bank Dallas, N.A.) gave notice to
Unit holders that it was resigning as the Trustee subject to certain conditions including the appointment of Southwest Bank as trustee of the Trust. At a special meeting of Trust Unit holders, the Unit holders approved the appointment of Southwest
Bank as successor trustee of the Trust, once Bank of America, N.A.s resignation took effect. The effective date of Bank of America, N.A.s resignation and the effective date of Southwest Banks appointment as successor trustee was
May 30, 2014. Effective October 19, 2017, Simmons First National Corporation (SFNC) completed its acquisition of First Texas BHC, Inc., the parent company of Southwest Bank. SFNC is the parent of Simmons Bank. SFNC merged Southwest Bank
with Simmons Bank effective February 20, 2018. The defined term Trustee as used herein shall refer to Bank of America, N.A. for periods prior to May 30, 2014 and shall refer to Southwest Bank for periods from May 30, 2014 through
February 19, 2018 and shall refer to Simmons Bank for periods on and after February 20, 2018. Because of the passive nature of the Trust and the
restrictions and limitations on the powers and activities of the Trustee contained in the Trust Agreement, the Trustee does not consider any of the officers and employees of the Trustee to be officers or executive officers of
the Trust as such terms are defined under applicable rules and regulations adopted under the Securities Exchange Act of 1934. The proceeds of
production from the Royalty Properties are receivable from hundreds of separate payors. In order to facilitate creation of the Trust and to avoid the administrative expense and inconvenience of daily reporting to Unit holders, the conveyances by
Sabine of the Royalty Properties located in five of the six states (Florida, Mississippi, New Mexico, Oklahoma, and Texas) provided for the execution of an escrow agreement by Sabine and the initial trustee of the Trust, in its capacities as trustee
of the Trust and as escrow agent. The conveyances by Sabine of the Royalty Properties located in Louisiana provided for the execution of a substantially identical escrow agreement by Sabine and a Louisiana bank in the capacities of escrow agent and
of trustee under the name of Sabine Louisiana Royalty Trust. Sabine Louisiana Royalty Trust, the sole beneficiary of which is the Trust, was established in order to avoid uncertainty under Louisiana law as to the legality of the Trustees
holding record title to the Royalty Properties located in Louisiana. Simmons Bank now serves as Trustee of the Sabine Louisiana Royalty Trust, since Louisiana law now permits an
out-of-state bank to act in this capacity. Therefore, the trust now only has one escrow agent, which is the Trustee, and a single escrow agreement. Pursuant to the terms of the escrow agreement and the conveyances of the properties by Sabine, the proceeds of production from the Royalty Properties
for each calendar month, and interest thereon, are collected by the escrow agent and are paid to and received by the Trust only on the next monthly record date. The escrow agent has agreed to endeavor to assure that it incurs and pays expenses and
fees for each calendar month only on the next monthly record date. The Trust Agreement also provides that the Trustee is to endeavor to assure that income of the Trust will be accrued and received and expenses of the Trust will be incurred and paid
only on each monthly record date. Assuming that the escrow agreement is recognized for federal income tax purposes and that the Trustee, as escrow agent is able to control the timing of income and expenses, as stated above, cash and accrual basis
Unit holders should be treated as realizing income only on each monthly record date. The Trustee is treating the escrow agreement as effective for tax purposes. However, for financial reporting purposes, royalty and interest income are recorded in
the calendar month in which the amounts are received by either the escrow agent or the Trust. Distributable income as determined for financial
reporting purposes for a given quarter will not usually equal the sum of distributions made during that quarter. Rather, distributable income for a given quarter will approximate the sum of the distributions made during the last two months of such
quarter and the first month of the next quarter.  40




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  2. Accounting Policies Basis of Accounting The financial statements of the Trust are
prepared on the following basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America:  

Royalty income, net of severance and ad valorem taxes, and interest income are recognized in the month in which amounts are
received by either the escrow agent or the Trust, pending verification of ownership and title (see Note 1).  

Trust expenses, consisting principally of routine general and administrative costs, include payments made during the
accounting period. Expenses are accrued to the extent of amounts that become payable on the next monthly record date following the end of the accounting period. Reserves for liabilities that are contingent or uncertain in amount may also be
established if considered necessary.  

Royalties that are producing properties are amortized using the unit-of-production method. This amortization is shown as a reduction of Trust corpus.  

Distributions to Unit holders are recognized when declared by the Trustee (see Note 3). The financial statements of the Trust differ from financial statements prepared in conformity with accounting principles generally accepted in the
United States of America because of the following:  

Royalty income is recognized in the month received, pending verification of ownership and title, rather than in the month
of production.  

Expenses other than those expected to be paid on the following monthly record date are not accrued.  

Amortization of the royalties is shown as a reduction to Trust corpus and not as a charge to operating results.  

Reserves may be established for contingencies that would not be recorded under accounting principles generally accepted in
the United States of America. This comprehensive basis of accounting other than accounting principles generally accepted in the
United States of America corresponds to the accounting permitted for royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E, Financial Statements of Royalty Trusts. Revenue Recognition Revenues from royalty interests are
recognized in the period in which amounts are received and verified by the Trust or escrow agent. Royalty income received by the Trust or escrow agent in a given calendar year will generally reflect the proceeds, on an entitlements basis, from
natural gas produced for the twelve-month period ended September 30th in that calendar year and from oil produced for the twelve-month period ended October 31st in the same calendar year. Contingencies Contingencies related to the Royalty
Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders. The Trustee is aware of no such
items as of December 31, 2019.  41




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  Use of Estimates The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions
that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates. Impairment The Trustee routinely reviews its royalty
interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trusts
royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting
projected cash flows. There is no impairment of the assets as of December 31, 2019. New Accounting Pronouncements There are no new pronouncements that are expected to have a significant impact on the Trusts financial statements. Distributable Income Per Unit Basic distributable income per
Unit is computed by dividing distributable income by the weighted average Units outstanding. Distributable income per Unit assuming dilution is computed by dividing distributable income by the weighted average number of Units and equivalent Units
outstanding. The Trust had no equivalent Units outstanding for any period presented. Therefore, basic distributable income per Unit and distributable income per Unit assuming dilution are the same. Federal Income Taxes The Internal Revenue Service has ruled
that the Trust is classified as a grantor trust for federal income tax purposes and therefore is not subject to taxation at the trust level. The Unit holders are considered, for federal income tax purposes, to own the Trusts income and
principal as though no trust were in existence. Accordingly, no provision for federal income tax expense has been made in these financial statements. The income of the Trust will be deemed to have been received or accrued by each Unit holder at the
time such income is received or accrued by the Trust, which is on the record date following the end of each month, as discussed above in Note 1. Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain
joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as middlemen). Therefore, the Trustee considers the Trust to be a non-mortgage widely
held fixed investment trust (WHFIT) for U.S. federal income tax purposes. Simmons Bank, EIN 71-0162300, 2911 Turtle Creek Blvd., Ste. 850, Dallas, Texas, 75219, telephone number 1-855-588-7839, email address trustee@sbr-sabine.com,
is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee
at www.sbr-sabine.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the
U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the
information that will be reported to them by the middlemen with respect to the Trust Units.  42




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  3. Distributions to Unit Holders The amount to be distributed to Unit holders (Monthly Income Amount) is determined on a monthly basis. The Monthly Income Amount is an amount
equal to the sum of cash received by the Trust during a monthly period (the period commencing on the day after a monthly record date and continuing through and including the next succeeding monthly record date) attributable to the Royalty
Properties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. Unit holders of record as of the monthly record date (the 15th day of
each calendar month except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for such month on or before 10 business days after the monthly record date. The Monthly Income Amount per Unit is
declared by the Trust no later than 10 days prior to the monthly record date. The cash received by the Trust is primarily from purchasers of
the Trusts oil and gas production and consists of gross sales of production less applicable severance taxes. In January 2019, the Trust received refunds of $309,879 (tax year 2015) from the State of Oklahoma and $140,474 (tax year 2015) from
the State of New Mexico. In March 2019, the Trust received a refund of $334,624 (tax year 2017) from the State of Oklahoma. In December 2019, the Trust received a refund of $86,535 from the State of New Mexico (tax year 2017). In July 2017, the
Trust received a refund of $288,521 (tax year 2016) from the State of Oklahoma and in August 2017, the Trust received a refund of $88,225 (tax year 2016) from the State of New Mexico. These refunds represented taxes that were withheld from the
proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and State of New Mexico by the applicable payors of such proceeds. Income taxes are not payable by the Trust, but are the responsibility of the individual Unit
holders. Therefore, the State of Oklahoma and the State of New Mexico refunded the withheld taxes, and the refunds were included as royalty income in the Trusts February 2019, April 2019, January 2020, August 2017 and September 2017
distributions, respectively. The Trust did file tax returns for 2017 and 2018 with the States of Oklahoma and New Mexico requesting refunds. The
Trust will file tax returns for 2019 with the States of Oklahoma and New Mexico requesting refunds. The refunds represent taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma and
the State of New Mexico by the applicable payors of such proceeds. 4. Other Payables Other payables consist of the following:  December 31,

2019


2018Royalty receipts in suspense pending verification of ownership interest or title

$
1,088,182


$
3,632,901 The Trustee believes that these amounts represent an ordinary operating condition of the Trust and that they will be
paid or released in the normal course of business. The royalty receipts in suspense pending verification of ownership interest or title as of December 31, 2018 includes the December 31, 2018 deposit of $2,602,834.76 which was processed by the third
party revenue service in January 2019.  43




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  5. Subsequent Events Distributions Subsequent to December 31,
2019, the Trust declared the following distributions:  Notification Date

Monthly Record Date

Payment Date

Distribution perUnitJanuary 3, 2020

January 15, 2020

January 29, 2020

$
0.303290February 6, 2020

February 18, 2020

February 28, 2020

$
0.218910 6. General and Administrative Expenses General and administrative expenses for the years ended December 31, were as follows:  2019


2018


2017Trustees fee

$
431,548


$
391,039


$
372,390Escrow agent fee paid to Trustee


1,294,648



1,173,117



1,117,169Professional fees


470,287



388,547



401,634Unit holders services fees


354,756



374,738



352,136Other


306,203



271,216



231,039Total General and Administrative Expenses


2,857,442



2,598,657



2,474,368 7. Quarterly Financial Data (Unaudited) The following table sets forth the royalty income, distributable income and distributable income per Unit of the Trust for each quarter in the years
ended December 31, 2019 and 2018 (in thousands, except per Unit amounts):  2019

RoyaltyIncome


DistributableIncome


DistributableIncome per UnitFirst Quarter

$
13,693


$
12,848


$
0.88Second Quarter


10,452



9,942



0.68Third Quarter


11,112



10,336



0.71Fourth Quarter


11,470



10,910



0.75$
46,727


$
44,036


$
3.02  2018

RoyaltyIncome


DistributableIncome


DistributableIncome per UnitFirst Quarter

$
10,750


$
9,932


$
0.68Second Quarter


13,139



12,544



0.86Third Quarter


11,857



11,321



0.78Fourth Quarter


16,640



16,132



1.10$
52,386


$
49,929


$
3.42  44




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  8. Supplemental Oil and Gas Information (Unaudited) Reserve Quantities Information regarding estimates of the
proved oil and gas reserves attributable to the Trust are based on reports prepared by DeGolyer and MacNaughton, independent petroleum engineering consultants. Estimates were prepared in accordance with the guidelines established by the FASB and the
Securities and Exchange Commission. Certain information required by this guidance is not presented because that information is not applicable to the Trust due to its passive nature. Oil and gas reserve quantities (all located in the United States) are estimates based on information available at the time of their preparation.
Such estimates are subject to change as additional information becomes available. Reserves actually recovered, and the timing of the production of those reserves, may differ substantially from original estimates. The following schedule presents
changes in the Trusts total proved reserves (in thousands):  Oil(Barrels)


Gas(Mcf)January 1, 2017


6,020



35,617Revisions of previous statements


1,100



4,976Production


(409
)


(4,038
)December 31, 2017


6,711



36,555Revisions of previous statements


961



2,997Production


(418
)


(4,282
)December 31, 2018


7,254



35,270Revisions of previous statements


355



4,524Production


(546
)


(4,373
)December 31, 2019


7,063



35,421 Estimated quantities of proved developed reserves of oil and gas as of the dates indicated were as follows (in
thousands):  Oil(Barrels)


NGL(Barrels)


Gas(Mcf)Proved Developed Reserves:January 1, 2017


4,298



1,702



32,845December 31, 2017


4,806



1,884



34,250December 31, 2018


5,097



2,157



35,270December 31, 2019


5,170



1,893



35,421 Disclosure of a Standardized Measure of Discounted Future Net Cash Flows The following is a summary of a standardized measure (in thousands) of discounted future net cash flows related to the Trusts total proved oil and
gas reserve quantities. Information presented is based upon a valuation of proved reserves by using discounted cash flows based upon average posted oil and gas prices ($55.85 per bbl and $2.62 per MMBtu, respectively) during the 12-month period prior to the fiscal year-end, 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 and severance and ad
valorem taxes, if any, and economic conditions, discounted at  45




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  the required rate of 10 percent. As the Trust is not subject to taxation at the trust level, no provision for income taxes has been made in the following disclosure. Based on oil and gas
product quality and property location, prices received by the Trust were slightly different than the posted prices above resulting in volume weighted average prices attributable to its proved reserves over the lives of the properties of $51.71 per
barrel of oil, $16.77 per barrel of NGL, and $2.11 per Mcf. The impact of changes in current prices on reserves could vary significantly from year
to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trusts oil and gas properties nor should it be viewed as indicative of any trends.  December 31,

2019


2018


2017Future net cash inflows

$
322,126


$
396,770


$
319,703Discount of future net cash flows @ 10%


(163,416
)


(206,444
)


(163,403
)Standardized measure of discounted future net cash inflows

$
158,710


$
190,326


$
156,300 The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2019,
2018 and, 2017 is as follows (in thousands):  2019


2018


2017Standardized measure of discounted future net cash flows, January 1,

$
190,326


$
156,300


$
121,084Royalty income, net of severance and ad valorem taxes


(46,727
)


(52,386
)


(37,163
)Changes in prices, net of related costs


(33,738
)


28,970



27,387Revisions of previous estimates and other


29,816



41,812



32,884Accretion of discount


19,033



15,630



12,108Standardized measure of discounted future net cash flows, December 31,

$
158,710


$
190,326


$
156,300 Subsequent to year end, the price of both oil and gas continued to fluctuate, giving rise to a correlating adjustment of
the respective standardized measure of discounted future net cash flows. As of February 10, 2020, NYMEX posted oil prices were approximately $49.59 per barrel, which compared to the average posted price of $55.85 per barrel, used to calculate
the worth of future net revenue of the Trusts proved developed reserves, would result in a decrease in the standardized measure of discounted future net cash flows for oil. As of February 10, 2020, NYMEX posted gas prices were $1.85 per
million British thermal units. The use of such price, as compared to the average posted price of $2.62 per million British thermal units, used to calculate the future net revenue for the Trusts proved developed reserves would result in a
decrease in the standardized measure of discounted future net cash flows for gas. 9. State Taxes Texas does not impose an individual income tax. Therefore, no part of the income produced by the Trust is subject to an individual income tax in Texas.
However, Texas imposes a franchise tax at a rate of 0.75% on gross revenues less certain deductions, as specifically set forth in the Texas franchise tax statutes. Entities subject to tax generally include trusts and most other types of entities
having limited liability protection, unless otherwise exempt. Trusts that receive at least 90% of their federal gross income from  46




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##### Table of Contents

SABINE ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS  (Continued)  designated passive sources, including royalties from mineral properties and other non-operated mineral interest income, and do not receive more than 10% of their income from operating an active
trade or business, are generally exempt from the Texas franchise tax as passive entities. The Trust has been and expects to continue to be exempt from Texas franchise tax as a passive entity. Because the Trust should be exempt from Texas
franchise tax at the Trust level as a passive entity, each Unit holder that is a taxable entity under the Texas franchise tax generally will be required to include its share of Trust revenues in its own Texas franchise tax computation. This revenue
is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the location of the day-to-day operations of the Trust, which is Texas. Because the Trust distributes all of its net income to Unit holders, it should not be subject to income tax in Louisiana, Florida, Mississippi, New
Mexico or Oklahoma. While the Trust should not owe tax, Unit holders may have a state filing responsibility in each of those states. Unit holders
should consult their own tax advisors regarding state tax requirements, if any, applicable to ownership of Trust Units.  *****  47




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##### Table of Contents

Item 9.Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure. None. Item 9A.Controls and Procedures. Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures The Trustee conducted an evaluation of the Trusts disclosure controls and procedures, as such term is defined under Rule 13a-15(e) promulgated
under the Securities Exchange Act of 1934, as amended. Based on this evaluation, the Trustee has concluded that the Trusts disclosure controls and procedures were effective as of the end of the period covered by this annual report. Changes in Internal Control Over Financial Reporting There
has not been any change in the Trusts internal control over financial reporting during the fourth quarter of 2019 that has materially affected, or is reasonably likely to materially affect, the Trusts internal control over financial
reporting. Trustees Report on Internal Control Over Financial Reporting The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f)
promulgated under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the
modified cash basis of accounting. 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, 2019. The independent registered public accounting firm of Weaver and Tidwell, L.L.P., as auditors of the statements of assets, liabilities, and trust corpus as of
December 31, 2019, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2019, has issued an attestation report on the Trusts internal control over financial reporting, which is
included herein.  48




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##### Table of Contents

Report of Independent Registered Public Accounting Firm To the Unit Holders of Sabine Royalty Trust and Simmons Bank, Trustee Opinion on Internal Control Over Financial Reporting We have audited Sabine Royalty Trust (the Trust)s internal control over financial reporting as of December 31, 2019 based on criteria
established in Internal Control - Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). In our opinion, the Trust maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2019, based on the COSO criteria. We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States) (PCAOB), the statements of assets, liabilities, and trust corpus of Sabine Royalty Trust as of December 31, 2019 and 2018 and the related statements of distributable income and changes in
trust corpus for each of the three years in the period ended December 31, 2019, and our report dated March 2, 2020 expressed an unqualified opinion thereon. Basis for Opinion The Trustee is responsible for maintaining
effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Trustees Report on Internal Control Over Financial Reporting. Our
responsibility is to express an opinion on the Trusts internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to Sabine Royalty
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 audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial
reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we
considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control
Over Financial Reporting An entitys internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting described in Note 2 to the financial statements. An entitys internal
control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the entity; (2)
provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with the modified cash basis of accounting described in Note 2 to the financial statements, and that receipts and
expenditures of the entity are being made only in accordance with authorizations of the Trustee and directors of the entity; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the entitys assets that could have a material effect on the financial statements.  49




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##### Table of Contents

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. /s/ WEAVER AND TIDWELL, L.L.P. Dallas, Texas March 2, 2020  50




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##### Table of Contents

Item 9B.Other Information. None. PART III Item 10.Directors and Executive Officers and Corporate Governance. Directors and Executive Officers.    The Registrant has no directors or executive officers. The Trustee is a corporate trustee
which may be removed, with or without cause, by the affirmative vote at a meeting duly called and held of the holders of a majority of the Units represented at the meeting. Compliance with Section 16(a) of the Exchange Act.    The Trust has no directors and officers and knows of no Unit
holder that is a beneficial owner of more than ten percent of the outstanding Units, and is therefore unaware of any person that failed to report on a timely basis reports required by Section 16(a) of the Securities Exchange Act of 1934, as
amended. Code of Ethics.Because the Trust has no employees, it does not have a code of ethics. Employees of the
Trustee, Simmons Bank, must comply with the banks code of ethics which may be found at http://ir.simmonsbank.com/govdocs. Audit
Committee.The Trust has no directors and therefore has no audit committee or audit committee financial expert. Nominating Committee.The Trust has no directors and therefore has no nominating committee. Item 11.Executive Compensation. Not applicable. Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. (a) Security Ownership
of Certain Beneficial Owners.Based on the Trustees review of information filed with the SEC as of February 24, 2020, the following table sets forth information with respect to each person known to the Trustee to beneficially own more
than 5% of the outstanding Units:  Name and Address

Amount and Natureof Beneficial Ownership

Percent ofClassFayez Sarofim
Two Houston Center, Suite 2907
909 Fannin Street
Houston, TX 77010

801,249(1)

5.5%  (1)
Pursuant to a Schedule 13G/A filed February 9, 2018, Fayez Sarofim reported as of December 31, 2017, he directly and
through certain entities of which he is a controlling person beneficially owned 801,249 Units, of which he had sole voting and dispositive power with respect to 650,000 Units and shared voting and dispositive power with respect to 151,249 Units. (b) Security Ownership of Management. The Trust has no directors or executive officers. (c) Changes in Control.The Trustee knows of no arrangements the operation of which may at a subsequent date result in a
change in control of the Registrant.  51




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##### Table of Contents

(d) Securities Authorized for Issuance Under Equity Compensation
Plans.The Trust has no equity compensation plans. Item 13.Certain Relationships and
Related Transactions, and Director Independence. Not applicable. Item 14.Principal Accounting Fees and Services. Fees for services performed by Deloitte & Touche LLP and Weaver and Tidwell, L.L.P. for the years ended December 31, 2019 and 2018 are:  2019


2018Audit fees: Deloitte & Touche LLP(1)

$
0


$
3,250Audit fees - Weaver and Tidwell, L.L.P.

$
135,000


$
118,000Audit-related fees: Deloitte & Touche LLP

$
0


$
0Audit-related fees: Weaver and Tidwell, L.L.P.

$
0


$
0Tax fees: Deloitte & Touche LLP

$
30,850


$
29,360All other fees(2)

$
11,902


$
10,986  (1)
Deloitte & Touche LLP served as the Trusts independent public accounting firm through June 1, 2016, and
was replaced by Weaver and Tidwell, L.L.P. effective on that date. (2)
BKD was the firm engaged to audit the Statement of Fees and Expenses Paid by Sabine Royalty Trust to Simmons Bank,
as Trustee and Escrow Agent report, as per the Trust agreement, which is filed as Exhibit 99 to this Form 10-K. As
referenced in Item 10, above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP or Weaver and
Tidwell, L.L.P. PART IV Item 15.Exhibits, Financial Statement Schedules. (a) The following documents are filed as a part of this
report: 1. Financial Statements (included in Item 8 of this report) Reports of Independent Registered Public Accounting Firm Statements of Assets, Liabilities and Trust Corpus at December 31, 2019 and 2018 Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2019 Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2019 Notes to Financial Statements 2. Financial
Statement Schedules Financial statement schedules are omitted because of the absence of conditions under which they are required or because the
required information is included in the financial statements and notes thereto.  52




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3. Exhibits  (4)(a)
*



Sabine Corporation Royalty Trust Agreement effective as of December 31, 1982, by and between Sabine Corporation and InterFirst Bank Dallas, N.A., as trustee. (P)(b)
*



Sabine Corporation Louisiana Royalty Trust Agreement effective as of December 31, 1982, by and between Sabine Corporation and Hibernia National Bank in New Orleans, as trustee, and joined in by InterFirst Bank Dallas,
N.A., as trustee. (P)(23)




Consent of DeGolyer and MacNaughton.(31)




Rule 13a-14(a)(15d-14(a)) Certification.(32)




Certification by Simmons Bank, Trustee of Sabine Royalty Trust, dated March 2, 2019 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).(99)




Report dated February 14, 2020 of the special purpose statement of Fees and Expenses paid by Sabine Royalty Trust to Simmons Bank, as Trustee and Escrow Agent.
  *
Exhibits 4(a) and 4(b) are incorporated herein by reference to Exhibits 4(a) and 4(b), respectively, of the
Registrants Annual Report on Form 10-K for the year ended December 31, 1993. (P)
Paper exhibits.  53




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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.  SABINE ROYALTY TRUSTBY: SIMMONS BANK, TrusteeBy:

/s/    RON E. HOOPERRon E. Hooper SVP, Royalty Trust Management
 Date: March 2, 2020 (The
Registrant has no directors or executive officers.)  54