Sabine Royalty Trust (SBR) 10-K 2018 FY Annual report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form10-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, 2018

☐ 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	Name of Each Exchange on Which Registered
Units of Beneficial Interest	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 ofRegulation 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 if disclosure of delinquent filers pursuant to Item 405 ofRegulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of thisForm 10-K or any amendment to thisForm 10-K.  ☒

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, anon-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” inRule 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 inRule 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 bynon-affiliates of the registrant was approximately $687 million.

At March 13, 2019, there were 14,579,345 units of beneficial interest outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None

TABLE OF CONTENTS

		Page
PART I
Item 1.	Business		1
	Description of the Trust		1
	Assets of the Trust		2
	Liabilities of the Trust		2
	Duties and Limited Powers of Trustee		3
	Liabilities of Trustee		3
	Duration of Trust		3
	Voting Rights of Unit Holders		4
	Description of Units		4
	Distributions of Net Income		4
	Transfer		5
	Reports to Unit Holders		5
	Widely Held Fixed Investment Trust Reporting Information		5
	Liability of Unit Holders		6
	Possible Divestiture of Units		6
	Federal Taxation		6
	State Tax Considerations		9
	Regulation and Prices		10
	Regulation		10
	Prices		15
Item 1A.	Risk Factors		15
Item 1B.	Unresolved Staff Comments		18
Item 2.	Properties		19
	Title		19
	Reserves		19
Item 3.	Legal Proceedings		28
Item 4.	Mine Safety Disclosures		28
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		29
Item 6.	Selected Financial Data		29
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		33
Item 8.	Financial Statements and Supplementary Data		34
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		45
Item 9A.	Controls and Procedures		45
Item 9B.	Other Information		47
PART III
Item 10.	Directors and Executive Officers and Corporate Governance		47
Item 11.	Executive Compensation		47
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		47
Item 13.	Certain Relationships and Related Transactions, and Director Independence		48
Item 14.	Principal Accounting Fees and Services		48
PART IV
Item 15.	Exhibits, Financial Statement Schedules		48

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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 onForm 10-K, quarterly reports onForm 10-Q, current reports onForm 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 athttp://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 anout-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

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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 theForm 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 insurance and trustee’s fees, accounting, engineering, legal and other professional fees. The total general and administrative expenses for the trust for 2018 were $2,598,657 of which, pursuant to the terms of the Trust Agreement, $64,716 was paid to Southwest Bank and $326,323 was paid to Simmons Bank, as Trustee, and $194,148 was paid to Southwest Bank and $978,969 was paid to Simmons Bank as escrow agent.

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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.”

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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 specifiednon-cash consideration, in which event the Trustee may, but is not obligated to, consummate suchnon-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 periodicre-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 13, 2019, 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.

Distributions of Net Income

The identity of Unit holders entitled to receive distributions of Trust 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

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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 street name, referred to here in collectively as “middlemen”). Therefore, the Trustee considers the Trust to be anon-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 addresstrustee@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 atwww.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

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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 the90-day period following the termination of the30-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 theover-the-counter market, as of the last business day prior to the expiration of the30-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.

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 would be 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.

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Transferees of Units transferred after October 11, 1990, may be eligible to use the percentage depletion deduction on oil and gas income thereafter attributable to such Units, if the percentage depletion deduction would exceed 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 deductions for depletion 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 property that was placed in service by the taxpayer after December 31, 1986. Detailed rules set forth inSections 1.1254-1through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Service will likely 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 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.

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. 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.

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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 recently-enacted tax legislation under 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 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.

For tax years beginning before January 1, 2018, the highest marginal U.S. federal income tax rate applicable to ordinary income of individuals is 39.6%, and the highest marginal U.S. federal income tax rate applicable to long-term capital gains and qualified dividends of individuals is 20%. For such pre-2018 tax years, such marginal tax rates may be effectively increased by up to 1.2% due to the phaseout of personal exemptions and the limitations on itemized deductions. For such pre-2018 tax years, the highest marginal U.S. federal income tax rate applicable to corporations is 35%, 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

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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 .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 designated passive sources, including royalties from mineral properties and othernon-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 theday-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 andnon-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 thebuilt-in gains tax or passive investment income tax), which will apply to royalty income allocable to a corporate Unit holder

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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.

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

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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 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 original conduct, 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.”

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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 become increasingly more stringent. 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. Under these laws, removal or remediation of current releases of such materials or of previously disposed wastes or property contamination at a drill site or a waste disposal facility could be required by a governmental authority 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 those actions were taken could be required by a governmental authority.

Disposal Wells

The federal Safe Drinking Water Act (“SDWA”) and 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 casing 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 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 would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the 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. Those petitions are currently pending. 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. To date, no further action has been taken by EPA with respect to the issue, but should 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 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

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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 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 is that the 2015 WOTUS definition is currently in effect in 22 states. 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 proposed rule would narrow the definition, excluding, for example, streams that do not flow year-round and wetlands without a direct surface connection to other jurisdictional waters. Litigation by parties opposing the rule quickly followed. Due to the administrative procedures required to establish the rule and pending litigation, the new definition of “Waters of the United States” may not be implemented, if at all, for several years. 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 United States Environmental Protection Agency (“EPA”) has issued greenhouse gas monitoring and reporting regulations. Under those rules, since 2012, persons that hold state drilling permits that emit 25,000 metric tons or more of carbon dioxide equivalent per year have been required to annually report their greenhouse gas emissions.

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

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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 also apply to storage tanks, natural gas wells, and other equipment. In May 2016, EPA issued a suite of new final regulations 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 2016 requirements, including reducing the required frequency of fugitive emissions monitoring at well site and compressor stations. Accordingly, the ultimate scope of these regulations is 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 has announced that it is 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 the 2016 rule. Several of the EPA’s and 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 the drilling operation. Texas and Oklahoma 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 are suing the BLM and the Secretary of the U.S. Department of the Interior over the repeal. 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 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.

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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 increased from $46.81 in 2017 to $58.91 in 2018. The Trustee believes that the decrease in production levels of the OPEC countries along with an increase in demand of oil due to a more stable economy led to the increase in the price of oil in 2018. Oil prices remained volatile in 2018 and showed a mostly upward trend prices for most of the year. Beginning with the fourth quarter of 2018, oil prices decreased significantly and have struggled to increase in the first quarter of 2019.

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 2018 on natural gas volumes sold of $2.67 per Mcf represented a decrease from the $2.95 per Mcf received in 2017, due largely to decreased demand mainly because of the active hurricane season on the east coast and in the Gulf of Mexico in 2018. The price of natural gas continues to be volatile and severe cold weather in early 2019 has helped natural gas prices to increase slightly.

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 amonth-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;

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

• the level of consumer demand;

• 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, net 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.

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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.

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

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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.

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 consecutivetwo-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.

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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 periodicre-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.

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, 2018, which comments remain unresolved.

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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, 2018.

	Mineral and Royalty
State	Gross Acres		Net Acres
Florida		5,448		697
Louisiana		244,391		23,682
Mississippi		75,489		9,713
New Mexico		112,294		9,141
Oklahoma		381,538		67,558
Texas		1,273,132		105,760
Total		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 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, 2019 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 information

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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. Steven R. Gilbert, Senior Vice President with DeGolyer and MacNaughton, was the primary engineer responsible for the report. Mr. Gilbert’s qualifications are set forth in the Certificate of Qualification attached to the letter report below.

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DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 25, 2019

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, 2019, 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 25, 2019. 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, 2019. 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, 2018. 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 the arbitrary 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.

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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 the12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

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.

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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 (Revision as of February 19, 2007).” 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, 2018, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through October 2018. Estimated cumulative production, as of January 1, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 2 months.

Oil and condensate reserves estimated herein are to be recovered by normal field separation. NGL reserves estimated herein include C5+ and liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions. NGL reserves are the result oflow-temperature plant processing. Oil, condensate, and NGL reserves included in this report are expressed in thousands of barrels (Mbbl) representing 42 United States gallons per barrel. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

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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 bothgas-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 owns 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 30 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 aproperty-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 thefirst-day-of-the-month price for each month within the12-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 $65.66 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 $60.43 per barrel of oil and condensate and $21.23 per barrel of NGL.

Gas Prices

The gas prices were based on a reference price, calculated as the unweighted arithmetic average of thefirst-day-of-the-month price for each month within the12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Differentials to the Henry Hub gas reference price of $3.16 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. Thevolume-weighted average price attributable to the estimated proved developed producing reserves over the lives of the properties was $2.804 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,

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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 Paragraphs932-235-50-4,932-235-50-6,932-235-50-7,932-235-50-9,932-235-50-30, and932-235-50-31(a), (b), and (e) of the Accounting Standards Update932-235-50,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 and proved undeveloped 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.

Summary of Conclusions

The estimated net proved developed producing reserves, as of January 1, 2019, of the properties evaluated herein were based on the definition of proved developed reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Estimated by DeGolyer and MacNaughton Net Proved Developed Producing Reserves as of January 1, 2019
State	Oil and Condensate (Mbbl)		NGL (Mbbl)		Total Liquids (Mbbl)		Sales Gas (MMcf)
Florida		63		4		67		0
Louisiana		43		1		44		230
Mississippi		74		0		74		478
New Mexico		269		147		416		1,810
Oklahoma		495		143		638		9,132
Texas		4,153		1,862		6,015		23,620
Total		5,097		2,157		7,254		35,270

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The estimated future revenue to be derived from the production and sale of the net proved developed producing reserves, as of January 1, 2019, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed Producing (M$)
Future Gross Revenue		452,716
Production Taxes		21,538
Ad Valorem Taxes		18,784
Transportation Expenses		15,624
Future Net Revenue		396,770
Present Worth at 10 Percent		190,326

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, 2019, estimated reserves.

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 FirmF-716

	/s/ Steven R. Gilbert
	Steven R. Gilbert, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

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CERTIFICATE of QUALIFICATION

I, Steven R. Gilbert, 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 25, 2019, 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 Missouri–Rolla, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1976; 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 34 years of experience in oil and gas reservoir studies and reserves evaluations.

	/s/ Steven R. Gilbert
	Steven R. Gilbert, P.E.
[SEAL]	Senior Vice President
	DeGolyer and MacNaughton

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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 2019 will be approximately $2,850,000.

The present value of future net revenue of the Trust’s proved developed reserves increased from $156,300,363 at January 1, 2018 to $190,325,591 at January 1, 2019. This increase resulted primarily from the prices used in the calculation of such amount, from an average price of $48.21 per barrel of oil, $15.92 per barrel of NGL and $2.86 per Mcf of gas at January 1, 2018 to 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.

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 19, 2019, NYMEX posted oil prices were approximately $56.12 per barrel, which compared to the average posted price of $65.66 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 19, 2019, NYMEX posted gas prices were $2.69 per million British thermal units. The use of such price, as compared to the average posted price of $3.16 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 inoil-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.

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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 25, 2019, there were 14,579,345 Units outstanding and approximately 1,051 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	2018		2017		2016		2015		2014
Royalty Income	$	52,386,070	$	37,162,911	$	30,022,292	$	48,386,010	$	61,089,631
Distributable Income		49,929,702		34,729,057		27,475,994		45,964,673		58,687,974
Distributable Income per Unit		3.42		2.38		1.88		3.15		4.03
Total Assets at Year End		9,464,382		5,330,266		5,234,447		6,113,447		6,845,405
Distributions per Unit		3.35		2.37		1.93		3.11		4.10

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.

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

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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 2016, 2017, and 2018.

Net royalty income during 2018 increased approximately $15,223,000, or 41.0 percent, compared to 2017 net royalty income.

Revenues generated by sales of oil and gas increased in 2018 from 2017 as a result of higher oil and gas sales volumes ($11.9 million); along with higher oil prices ($6.7 million); offset somewhat by lower natural gas prices ($1.6 million) and higher expenses, taxes and revenue due others ($1.8 million).

Gas volumes increased from 5,681,137 thousand cubic feet (“Mcf”) in 2017 to 7,138,837 Mcf in 2018. The average price per Mcf of gas received by the Trust decreased from $2.95 in 2017 to $2.67 in 2018. 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.

Oil volumes sold increased to 689,799 barrels (“Bbls”) in 2018 from 553,558 Bbls in 2017. The average sales of oil increased to $58.91 per Bbl in 2018, 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 sector 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 and have struggled to increase in the first quarter of 2019.

Interest income was $142,000 in 2018, which had increased from $41,000 in 2017. Changes in interest interest income are the result of changes in interest rates and funds available for investment.

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 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 August 2017 and September 2017 distributions, respectively.

The Trust did file tax returns for 2017 with the States of Oklahoma and New Mexico requesting refunds. The Trust will file tax returns for 2018 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.

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.

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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.

• 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 theunit-of-production method. This amortization is shown as a reduction of Trust corpus.

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

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 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 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 the12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of thefirst-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 ofnon-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.

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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, 2018.

New Accounting Pronouncements

Revenue Recognition –In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods and services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Trust has adopted this standards update, as required, beginning with the first quarter of 2018. The adoption of this standard has not had a significant impact on its financial statements due to the modified cash basis of reporting used by the Trust.

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 anyoff-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 2018. The following table presents the weighted average prices received per year by the Trust:

	Oil Per BBL		Gas Per Mcf
2018	$	58.91	$	2.67
2017		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 inoil-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”.

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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.

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Item 8.Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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, 2018 and 2017, and the related statements of distributable income and changes in trust corpus for the years then ended, 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, 2018 and 2017, and the distributable income and changes in trust corpus for the years then ended, 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, 2018, 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 13, 2019 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.

/s/ WEAVER AND TIDWELL, L.L.P.

We have served as the Trust’s auditor since 2016.

Dallas, Texas

March 13, 2019

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SABINE ROYALTY TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2018		2017
Assets
Cash and short-term investments	$	9,250,494	$	5,085,661
Royalty interests in oil and gas properties less accumulated amortization of $22,181,297 (2018) and $22,150,580 (2017)		213,888		244,605
Total	$	9,464,382	$	5,330,266
Liabilities and Trust Corpus
Trust expenses payable	$	165,216	$	165,041
Other payables (Note 4)		3,632,901		570,841
Total liabilities		3,798,117		735,882
Contingencies (Note 2)
Trust Corpus (14,579,345 units of beneficial interest authorized and outstanding)		5,666,265		4,594,384
Total	$	9,464,382	$	5,330,266

Statements of Distributable Income

	Year Ended December 31,
	2018		2017
Royalty Income	$	52,386,070	$	37,162,911
Interest Income		142,289		40,514
Total		52,528,359		37,203,425
General and administrative expenses (Note 6)		2,598,657		2,474,368
Distributable income	$	49,929,702	$	34,729,057
Distributable income per unit (Basic and Assuming Dilution) (14,579,345 units) (Notes 1,2)	$	3.42	$	2.38

Statements of Changes in Trust Corpus

	2018			2017
Trust corpus, beginning of year	$	4,594,384		$	4,423,299
Amortization of royalty interests		(30,717	)		(28,685	)
Distributable income		49,929,702			34,729,057
Distributions to unit holders (Note 3)		(48,827,104	)		(34,529,287	)
Trust corpus, end of year	$	5,666,265		$	4,594,384
Distributions per unit (Note 3)	$	3.35		$	2.37

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

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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).

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

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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 anout-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.

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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 (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 theunit-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 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 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, 2018.

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.

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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, 2018.

New Accounting Pronouncements

Revenue Recognition –In May 2014, the FASB issued updated guidance for recognizing revenue from contracts with customers. This update amends the existing accounting standards for revenue recognition and is based on the principle that revenue should be recognized to depict the transfer of goods and services to a customer at an amount that reflects the consideration a company expects to receive in exchange for those goods or services. The Trust will adopt this standards update, as required, beginning with the first quarter of 2018, but does not believe the adoption of this standard will have a significant impact on its financial statements due to the modified cash basis of reporting used by the Trust.

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 anon-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 atwww.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.

39

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 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 August 2017 and September 2017 distributions, respectively.

The Trust did file tax returns for 2017 with the States of Oklahoma and New Mexico requesting refunds. The Trust will file tax returns for 2018 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,	2018		2017
Royalty receipts in suspense pending verification of ownership interest or title	$	3,632,901	$	570,841

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.

5. Subsequent Events

Distributions

Subsequent to December 31, 2018, the Trust declared the following distributions:

Notification Date	Monthly Record Date	Payment Date	Distribution per Unit
January 4, 2019	January 15, 2019	January 29, 2019	$	0.302650
February 5, 2019	February 15, 2019	February 28, 2019	$	0.251090
March 5, 2019	March 15, 2019	March 29, 2019	$	0.278540

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

6. General and Administrative Expenses

General and administrative expenses for the years ended December 31, were as follows:

	2018		2017
Trustee’s fee	$	391,039	$	372,390
Escrow agent fee paid to Trustee		1,173,117		1,117,169
Professional fees		388,547		401,634
Unit holders’ services fees		374,738		352,136
Other		271,216		231,039
Total General and Administrative Expenses		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, 2018 and 2017 (in thousands, except per Unit amounts):

2018	Royalty Income		Distributable Income		Distributable Income per Unit
First Quarter	$	10,750	$	9,932	$	0.68
Second Quarter		13,139		12,544		0.86
Third Quarter		11,857		11,321		0.78
Fourth Quarter		16,640		16,132		1.10
	$	52,386	$	49,929	$	3.42

2017	Royalty Income		Distributable Income		Distributable Income per Unit
First Quarter	$	10,482	$	9,807	$	0.67
Second Quarter		8,570		7,900		0.54
Third Quarter		9,098		8,521		0.58
Fourth Quarter		9,013		8,501		0.59
	$	37,163	$	34,729	$	2.38

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.

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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, 2016		6,169			33,870
Revisions of previous statements		244			5,986
Production		(393	)		(4,239	)
December 31, 2016		6,020			35,617
Revisions of previous statements		1,100			4,976
Production		(409	)		(4,038	)
December 31, 2017		6,711			36,555
Revisions of previous statements		961			2,997
Production		(418	)		(4,282	)
December 31, 2018		7,254			35,270

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

	Oil		NGL		Gas
	(Barrels)		(Barrels)		(Mcf)
Proved Developed Reserves:
January 1, 2016		4,398		1,632		31,006
December 31, 2016		4,298		1,702		32,845
December 31, 2017		4,806		1,884		34,250
December 31, 2018		5,097		2,157		35,270

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 ($65.66 per bbl and $3.16 per MMBtu, respectively) during the12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of thefirst-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 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 $60.43 per barrel of oil, $21.23 per barrel of NGL, and $2.80 per Mcf.

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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,	2018			2017			2016
Future net cash inflows	$	396,770		$	319,703		$	238,365
Discount of future net cash flows @ 10%		(206,444	)		(163,403	)		(117,281	)
Standardized measure of discounted future net cash inflows	$	190,326		$	156,300		$	121,084

The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2018, 2017 and, 2016 is as follows (in thousands):

	2018			2017			2016
Standardized measure of discounted future net cash flows, January 1,	$	156,300		$	121,084		$	140,342
Royalty income, net of severance and ad valorem taxes		(52,386	)		(37,163	)		(30,022	)
Changes in prices, net of related costs		28,970			27,387			(20,688	)
Revisions of previous estimates and other		41,812			32,884			17,418
Accretion of discount		15,630			12,108			14,034
Standardized measure of discounted future net cash flows, December 31,	$	190,326		$	156,300		$	121,084

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 19, 2019, NYMEX posted oil prices were approximately $56.12 per barrel, which compared to the average posted price of $65.66 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 19, 2019, NYMEX posted gas prices were $2.69 per million British thermal units. The use of such price, as compared to the average posted price of $3.16 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 .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 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

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SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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.

*****

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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 2018 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 inInternal Control — Integrated Framework 2013 issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework inInternal Control — Integrated Framework 2013, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2018. 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, 2018, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2018, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.

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Report of Independent Registered Public Accounting Firm

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, 2018 based on criteria established inInternal 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, 2018, 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, 2018 and 2017 and the related statements of distributable income and changes in trust corpus for the years then ended and our report dated March 13, 2019 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.

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 13, 2019

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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 athttp://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 26, 2019, 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 Nature of Beneficial Ownership	Percent of Class
Fayez 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.

(d) Securities Authorized for Issuance Under Equity Compensation Plans.    The Trust has no equity compensation plans.

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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, 2018 and 2017 are:

	2018		2017
Audit fees: Deloitte & Touche LLP	$	3,250	$	7,709
Audit fees - Weaver and Tidwell, L.L.P.	$	118,000	$	132,000
Audit-related fees: Deloitte & Touche LLP	$	0	$	0
Audit-related fees: Weaver and Tidwell, L.L.P.	$	0	$	0
Tax fees: Deloitte & Touche LLP	$	29,360	$	31,232
All other fees(2)	$	10,986	$	10,400

(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 Southwest Bank, as Trustee and Escrow Agent” report, as per the Trust agreement, which will be filed on a Form 8-K at a later date.

As referenced in Item 10, above, the Trust has no audit committee, and as a result, has no audit committeepre-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, 2018 and 2017

Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2018

Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2018

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.

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)

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(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 13, 2019 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).

* 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 onForm 10-K for the year ended December 31, 1993.

(P) Paper exhibits.

49

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 TRUST
BY: SIMMONS BANK, Trustee
By:	/s/    RON E. HOOPER
	Ron E. Hooper SVP, Royalty Trust Management

Date: March 13, 2019

(The Registrant has no directors or executive officers.)

50