10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

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

For the fiscal year ended December 31, 2013

¨ 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	75-6297143
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
Trust Division U.S. Trust, Bank of America Private Wealth Management Bank of America Plaza 17th Floor 901 Main Street Dallas, Texas	75202
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (214) 209-2400

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 x    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  x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  Yes x    No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes ¨    No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation 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 this Form 10-K or any amendment to this Form 10-K.  x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act (check one):

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

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

The aggregate market value of units of beneficial interest of the registrant (based on the closing sale price on the New York Stock Exchange as of the last business day of its most recently completed second fiscal quarter) held by non-affiliates of the registrant was approximately $753 million.

At February 26, 2014, 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		5
	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		12
Item 1A.	Risk Factors		13
Item 1B.	Unresolved Staff Comments		16
Item 2.	Properties		16
	Title		17
	Reserves		17
Item 3.	Legal Proceedings		25
Item 4.	Mine Safety Disclosures		25
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		26
Item 6.	Selected Financial Data		26
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		26
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		31
Item 8.	Financial Statements and Supplementary Data		32
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		43
Item 9A.	Controls and Procedures		43
Item 9B.	Other Information		45
PART III
Item 10.	Directors and Executive Officers and Corporate Governance		45
Item 11.	Executive Compensation		45
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		45
Item 13.	Certain Relationships and Related Transactions, and Director Independence		46
Item 14.	Principal Accounting Fees and Services		46
PART IV
Item 15.	Exhibits, Financial Statement Schedules		46

i

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 Bank of America, N.A. (as successor to NationsBank, N.A.) (“Bank of America”). In accordance with the successor trustee provisions of the Trust Agreement, Bank of America, as trustee of the Trust (the “Trustee”), is subject to all the terms and conditions of the Trust Agreement. In 2007 the Bank of America private wealth management group officially became known as “U.S. Trust, Bank of America Private Wealth Management.” The legal entity that serves as Trustee of the Trust did not change, and references in this Form 10-K to U.S. Trust, Bank of America Private Wealth Management shall describe the legal entity Bank of America, N.A. The principal office of the Trust (sometimes referred to herein as the “Registrant”) is located at Bank of America Plaza, 17th Floor, 901 Main Street, Dallas, Texas 75202. The telephone number of the Trust is (214) 209-2400.

On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management gave notice to Unit holders that it will be resigning as Trustee subject to the conditions set forth below. Bank of America, N.A. intends to nominate Southwest Bank, an independent state bank chartered under the laws of the State of Texas and headquartered in Fort Worth, Texas (“Southwest Bank”), as successor trustee at a meeting of Unit holders of the Trust to be called for the purpose of approving a successor trustee of the Trust. U.S. Trust, Bank of America Private Wealth Management’s resignation is conditioned on the satisfaction or waiver by U.S. Trust, Bank of America Private Wealth Management of each of the following: (i) the appointment of Southwest Bank as trustee of the Trust; (ii) the appointment of Southwest Bank or another successor trustee as trustee of six other royalty trusts for which U.S. Trust, Bank of America Private Wealth Management currently serves as trustee and as agent under a disbursing arrangement for which it currently serves as agent; (iii) the accuracy of certain representations and warranties and performance of certain agreements made by Southwest Bank in an agreement between U.S. Trust, Bank of America Private Wealth Management and Southwest Bank; and (iv) no governmental injunction, order or other action that would prohibit Southwest Bank’s appointment, U.S. Trust, Bank of America Private Wealth Management’s resignation or the other actions described above. The effective date of U.S. Trust, Bank of America Private Wealth Management’s resignation shall be May 30, 2014, assuming all of the conditions described above have been satisfied or waived as of such date.

The Trust maintains an Internet website, and as a result, reports such as its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to such reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, will now be made available at http://www.sbr-sabineroyalty.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

1

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. On December 31, 2001, Bank of America, N.A. assumed the duties as Trustee of the Sabine Louisiana Royalty Trust, since Louisiana law now permits an out-of-state bank to act in this capacity. A separate trust also was established to hold record title to the Royalty Properties located in Florida. Legislation was adopted in Florida in 1992 that eliminated the provision of Florida law that prohibited the Trustee from holding record title to the Royalty Properties located in that state. In November 1993, record title to the Royalty Properties held by the trustee of Sabine Florida Land Trust was transferred to the Trustee. As used herein, the term “Royalty Properties” includes the Royalty Properties held directly by the Trust and the Royalty Properties located in Louisiana and Florida that were held indirectly through the Trust’s ownership of 100 percent beneficial interest of Sabine Louisiana Royalty Trust and Sabine Florida Land Trust. In discussing the Trust, this report disregards the technical ownership formalities described in this paragraph, which have no effect on the tax or accounting treatment of the Royalty Properties, since the observance thereof would significantly complicate the information presented herein without any corresponding benefit to Unit holders.

Certificates evidencing units of beneficial interest (the “Units”) in the Trust were mailed on December 31, 1982 to the shareholders of Sabine Corporation of record on December 23, 1982, on the basis of one Unit for each outstanding share of common stock of Sabine Corporation. The Units are listed and traded on the New York Stock Exchange under the symbol “SBR.”

In May 1988, Sabine Corporation was acquired by Pacific Enterprises, a California corporation. Through a series of mergers, Sabine Corporation was merged into Pacific Enterprises Oil Company (USA) (“Pacific (USA)”), a California corporation and a wholly owned subsidiary of Pacific Enterprises, effective January 1, 1990. This acquisition and the subsequent mergers had no effect on the Units. Pacific (USA), as successor to Sabine Corporation, assumed by operation of law all of Sabine Corporation’s rights and obligations with respect to the Trust. References herein to Pacific (USA) shall be deemed to include Sabine Corporation where appropriate.

In connection with the transfer of the Royalty Properties to the Trust upon its formation, Sabine Corporation had reserved to itself all executive rights, including rights to execute leases and to receive bonuses and delay rentals. In January 1993, Pacific (USA) completed the sale of substantially all of Pacific (USA)’s producing oil and gas assets to Hunt Oil Company. The sale did not include the executive rights relating to the Royalty Properties, and Pacific (USA)’s ownership of such rights was not affected by the sale.

The following summaries of certain provisions of the Trust Agreement are qualified in their entirety by reference to the Trust Agreement itself, which is an exhibit to the Form 10-K and available upon request from the Trustee. The definitions, formulas, accounting procedures and other terms governing the Trust are complex and extensive and no attempt has been made below to describe all such provisions. Capitalized terms not otherwise defined herein are used with the meanings ascribed to them in the Trust Agreement.

Assets of the Trust

The Royalty Properties are the only assets of the Trust, other than cash being held for the payment of expenses and liabilities and for distribution to the Unit holders. Pending such payment of expenses and distribution to Unit holders, cash may be invested by the Trustee only in certificates of deposit, United States government securities or repurchase agreements secured by United States government securities. 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

2

total general and administrative expenses of the Trust for 2013 were $2,066,007 of which, pursuant to the terms of the Trust Agreement, $295,294 was paid to U.S. Trust, Bank of America Private Wealth Management, as Trustee, and $885,863 was paid to U.S. Trust, Bank of America Private Wealth Management, as escrow agent.

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 or repurchase agreements secured by United States government securities. 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

3

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.”

Upon the termination of the Trust, the Trustee will continue to act in such capacity until all the assets of the Trust are distributed. The Trustee will sell all Trust properties for cash (unless the Unit holders authorize the sale for a specified non-cash consideration, in which event the Trustee may, but is not obligated to, consummate such non-cash sale) in one or more sales and, after satisfying all existing liabilities and establishing adequate reserves for the payment of contingent liabilities, will distribute all available proceeds to the Unit holders.

Voting Rights of Unit Holders

Although Unit holders possess certain voting rights, their voting rights are not comparable to those of shareholders of a corporation. For example, there is no requirement for annual meetings of Unit holders or for annual or other periodic re-election of the Trustee.

The Trust Agreement may be amended by the affirmative vote of a majority of the outstanding Units at any duly called meeting of Unit holders. However, no such amendment may alter the relative rights of Unit holders unless approved by the affirmative vote of 100 percent of the Unit holders and by the Trustee. In addition, certain special voting requirements can be amended only if such amendment is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee.

Removal of the Trustee requires the affirmative vote of the holders of a majority of the Units represented at a duly called meeting of Unit holders. In the event of a vacancy in the position of Trustee or if the Trustee has given notice of its intention to resign, a successor trustee of the Trust may be appointed by similar voting approval of the Unit holders.

The sale of all or any part of the assets of the Trust must be authorized by the affirmative vote of the holders of a majority of the outstanding Units. However, the Trustee may, without a vote of the Unit holders, sell all or any part of the Trust assets upon termination of the Trust or otherwise if necessary to provide for the payment of specific liabilities of the Trust then due. The Trust can be terminated by the Unit holders only if the termination is approved by the holders of a majority of the outstanding Units.

Meetings of Unit holders may be called by the Trustee at any time at its discretion and must be called by the Trustee at the written request of holders of not less than 10 percent of the then outstanding Units. The presence of a majority of the outstanding Units is necessary to constitute a quorum and Unit holders may vote in person or by proxy.

Notice of any meeting of Unit holders must be given not more than 60 nor less than 20 days prior to the date of such meeting. The notice must state the purposes of the meeting and no other matter may be presented or acted upon at the meeting.

DESCRIPTION OF UNITS

Each Unit represents an equal undivided share of beneficial interest in the Trust and is evidenced by a transferable certificate issued by the Trustee. Each Unit entitles its holder to the same rights as the holder of any other Unit, and the Trust has no other authorized or outstanding class of equity security. At February 26, 2014, there were 14,579,345 Units outstanding.

The Trust may not issue additional Units unless such issuance is approved by the holders of at least 80 percent of the outstanding Units and by the Trustee. Under limited circumstances, Units may be redeemed by the Trust and canceled. See “Possible Divestiture of Units” below.

4

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 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 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 Bank of America, as 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 a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank

5

of America Private Wealth Management, EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, email address trustee@sbr-sabineroyalty.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabineroyalty.com. Notwithstanding the foregoing, the middlemen holding Trust Units on behalf of Unit holders, and not the Trustee of the Trust, are solely responsible for complying with the information reporting requirements under the U.S. Treasury Regulations with respect to such Trust Units, including the issuance of IRS Forms 1099 and certain written tax statements. Unit holders whose Trust Units are held by middlemen should consult with such middlemen regarding the information that will be reported to them by the middlemen with respect to the Trust Units.

Liability of Unit Holders

As regards the Unit holders, the Trustee, in engaging in any activity or transaction that results or could result in any kind of liability, will be fully liable if the Trustee fails to take reasonable steps necessary to ensure that such liability is satisfiable only out of the Trust assets (even if the assets are inadequate to satisfy the liability) and in no event out of amounts distributed to, or other assets owned by, Unit holders. However, the Trust might be held to constitute a “joint stock company” under Texas law, which is unsettled on this point, and therefore a Unit holder may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of both the Trust and the Trustee are not adequate to satisfy such liability. In view of the substantial value and passive nature of the Trust assets, the restrictions on the power of the Trustee to incur liabilities and the required financial net worth of any trustee of the Trust, the imposition of any liability on a Unit holder is believed to be extremely unlikely.

Possible Divestiture of Units

The Trust Agreement imposes no restrictions based on nationality or other status of the persons or entities which are eligible to hold Units. However, the Trust Agreement provides that if at any time the Trust or the Trustee is named a party in any judicial or administrative proceeding seeking the cancellation or forfeiture of any property in which the Trust has an interest because of the nationality, or any other status, of any one or more Unit holders, the following procedure will be applicable:

1. The Trustee will give written notice to each holder whose nationality or other status is an issue in the proceeding of the existence of such controversy. The notice will contain a reasonable summary of such controversy and will constitute a demand to each such holder that he or she dispose of his or her Units within 30 days to a party not of the nationality or other status at issue in the proceeding described in the notice.

2. If any holder fails to dispose of his or her Units in accordance with such notice, the Trustee shall have the preemptive right to redeem and shall redeem, at any time during the 90-day period following the termination of the 30-day period specified in the notice, any Unit not so transferred for a cash price equal to the closing price of the Units on the stock exchange on which the Units are then listed or, in the absence of any such listing, the mean between the closing bid and asked prices for the Units in the over-the-counter market, as of the last business day prior to the expiration of the 30-day period stated in the notice.

3. The Trustee shall cancel any Unit acquired in accordance with the foregoing procedures.

4. The Trustee may, in its sole discretion, cause the Trust to borrow any amount required to redeem Units.

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.

6

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.

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.

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 in Sections 1.1254-1 through 1.1254-6 of the U.S. Treasury Regulations govern dispositions of property after March 13, 1995. The Service 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.

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

7

income from the Royalty Properties for a calendar month and interest income thereon will be taxed to the holder of the Unit on the next Monthly Record Date without regard to the ownership of the Unit prior to that date. The Trustee is treating the escrow arrangement as effective for tax purposes and furnishes tax information to Unit holders on that basis.

The Service might take the position that the escrow arrangement should be ignored for federal tax purposes. In such case, the Trustee could be required to report the proceeds from production and interest income thereon to the Unit holders on a daily basis, in accordance with their method of accounting, as the proceeds from production and interest thereon were received or accrued by the escrow agent. Such reporting could impact who is taxed on the production and interest income and result in a substantial increase in the administrative expenses of the Trust. In the event of a transfer of a Unit, the income and the depletion deduction attributable to the Royalty Properties for the period up to the date of transfer would be allocated to the transferor, and the income and depletion deduction attributable to the Royalty Properties on and after the date of transfer would be allocated to the transferee. Such allocation would be required even though the transferee was the holder of the Unit on the next Monthly Record Date and, therefore, would be entitled to the monthly income distribution. Thus, if the escrow arrangement is not recognized, a mismatching of the monthly income distribution and the Unit holder’s taxable income and deductions could occur between a transferor and a transferee upon the transfer of a Unit.

Unit holders of record on each Monthly Record Date are entitled to receive monthly distributions. See “Description of Units — Distributions of Net Income” above. The terms of the escrow agreement and the Trust Agreement, as described above, seek to assure that taxable income attributable to such distributions will be reported by the Unit holder who receives such distributions, assuming that such holder is the holder of record on the Monthly Record Date. In certain circumstances, however, a Unit holder may be required to report taxable income attributable to his or her Units but the Unit holder will not receive the distribution attributable to such income. For example, if the Trustee establishes a reserve or borrows money to satisfy debts and liabilities of the Trust, income used to establish such reserve or to repay such loan will be reported by the Unit holder, even though such income is not distributed to the Unit holder.

Interest and royalty income attributable to ownership of Units and any gain on the sale thereof are considered portfolio income, and not income from a “passive activity,” to the extent a Unit holder acquires and holds Units as an investment and not in the ordinary course of a trade or business. Therefore, interest and royalty income attributable to ownership of Units generally may not be offset by losses from any passive activities.

Individuals may incur expenses in connection with the acquisition or maintenance of Trust Units. These expenses may be deductible as “miscellaneous itemized deductions” only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income.

Under current law, 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 (generally, gains from the sale or exchange of certain investment assets held for more than one year) and qualified dividends of individuals is 20%. 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. 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.

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a Unit holder’s allocable share of the Trust’s interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status. In the case of an estate or trust, the tax is imposed on the lesser of (i) undistributed net investment income,

8

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 recently issued guidance providing that the FATCA withholding rules described above generally will only 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 income tax. Therefore, no part of the income produced by the Trust is subject to an income tax in Texas. However, Texas imposes a franchise tax at a rate of 1% 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 considered a taxable entity under the Texas franchise tax would generally be required to include its share of Trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the location of the day-to-day operations of the Trust, which is Texas.

Louisiana.    The Trustee is required to file with Louisiana a return reflecting the income of the Trust attributable to mineral interests located in Louisiana. Both Louisiana resident and non-resident Unit holders may be subject to the Louisiana personal, corporate and/or franchise tax as certain income and expenses from the Trust are from sources within Louisiana.

Florida, Mississippi, New Mexico and Oklahoma.    Florida does not have a personal income tax. Florida imposes an income tax on resident and nonresident corporations (except for S corporations not subject to the built-in gains tax or passive investment income tax), which will be applicable to royalty income allocable to a corporate Unit holder from properties located within Florida. Mississippi, New Mexico and Oklahoma each impose an income tax applicable to both resident and nonresident individuals and/or corporations (subject to certain

9

exceptions for S corporations and limited liability companies, depending on their treatment for federal tax purposes), which will be applicable 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 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 has filed New Mexico and Oklahoma tax returns, obtained a refund, and distributed 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, and local levels. Oil and gas development and production activities are subject to state law, regulation 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 to issue, and have issued, rules and regulations binding on the oil and gas industry which are often difficult and costly to comply with and which impose substantial penalties for the failure to comply.

Natural Gas

Prices for the sale of natural gas, like the sale of other commodities, are governed by the marketplace and the provisions of applicable gas sales contracts. The Federal Energy Regulatory Commission (“FERC”), which principally is responsible for regulating interstate transportation and the sale of natural gas, has taken significant steps in the implementation of a policy to restructure the natural gas pipeline industry to promote full competition in the sales of natural gas, so that all natural gas suppliers, including pipelines, can compete equally for sales

10

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 federal, 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, state and local laws, rules and regulations regulating health; safety; the acquisition of a permit before conducting drilling or underground injection activities; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands, endangered 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 of materials into the environment; or otherwise relating to the protection of the environment 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 Environmental Protection Agency 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. In the course of operations, the working interest owner and/or the operator of Royalty Properties may have generated and may generate wastes that may fall within CERCLA’s definition of “hazardous substances”. The operator of the Royalty Properties or the working interest owners may be responsible under CERCLA for all or part of the costs to clean up sites at which such substances have been disposed. Although the Trust is not the operator of any Royalty Properties, or the owner of any working interest, its ownership of royalty interests could cause it to be responsible for all or part of such costs to the extent CERCLA imposes responsibility on such parties as “owners.”

Solid and Hazardous Waste.    The Royalty Properties have produced oil and/or gas for many years, and, 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 disposed or released on or under the Royalty Properties by the current or previous operators. Federal, state and local laws applicable to oil and gas-related wastes and properties have become increasingly more stringent. Under these laws, removal or remediation of previously disposed wastes or property contamination could be required by a governmental authority.

11

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 (the “EPA”) issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and required reporting by regulated facilities by September 30, 2011 and annually thereafter. On November 30, 2010, the EPA published a final rule that set forth reporting requirements for the petroleum and natural gas industry and required persons that hold state drilling permits that emit 25,000 metric tons or more of carbon dioxide equivalent per year to report annually carbon dioxide, methane and nitrous oxide emissions from certain sources beginning on March 31, 2012. On November 30, 2011, the EPA published a final rule that established technical amendments to certain greenhouse gas reporting requirements and that extended the reporting deadline to September 2012 for the petroleum and natural gas industry sources to report their greenhouse gas emissions.

Beyond measuring and reporting, the 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. The EPA indicated that it will use data collected through the reporting rules to decide whether to promulgate future greenhouse gas emission limits. On April 17, 2012, the 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. Beginning January 1, 2015, all hydraulically fractured or refractured natural gas wells must be completed using so called “green completion” technology, which significantly reduces VOC emissions. Limiting emissions of VOCs will have the co-benefit of also limiting methane, a greenhouse gas. These regulations apply to natural gas wells that are hydraulically fractured or refractured, and to storage tanks and other equipment.

Congress and various states, including Texas, Louisiana, 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. Hydraulic fracturing has historically been regulated by state oil and natural gas commissions. The EPA, however, has asserted federal regulatory authority over certain hydraulic fracturing activities involving diesel under the Safe Drinking Water Act (the “SDWA”). The EPA has issued permitting guidance for oil and natural gas hydraulic fracturing activities using diesel fuel. Under that guidance, EPA defined the term “diesel” to include five categories of oils, including some such as kerosene, that are not traditionally considered to be diesel.

EPA is also conducting a congressionally mandated study on the effects of hydraulic fracturing on water at all stages in the operational cycle of harvesting natural gas, which is expected to be completed in 2014. This study is anticipated to form the basis for a comprehensive regulatory effort. The EPA study, or other studies, of hydraulic fracturing could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory programs. The re-election of President Obama makes such regulation of the oil and gas industry more likely.

The Trustee cannot predict the effect that noncompliance with existing environmental laws, rules and regulations; compliance with new legislation or regulation, or enforcement policies thereunder; or claims for damages to property, employees, other persons and the environment resulting from operations on the Royalty Properties could have on the Trust or Unit holders. Even if the Trust were not directly liable for costs or expenses related to these matters, increased costs to achieve compliance with existing or new environmental laws, rules or regulations or to respond to an enforcement action or a private party action could result in wells being plugged and abandoned earlier in their productive lives, resulting in a loss of reserves and revenues to the Trust.

Prices

Oil

The Trust’s average per barrel oil price decreased from $88.77 in 2012 to $86.84 in 2013. The Trustee believes that the slow economic recovery led to a decrease in demand for oil in 2013. Oil prices remained volatile in 2013 and the continued sluggishness of the economy as well as the uncertainty of the government’s response to this slow recovery will continue to affect the price of oil.

12

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 2013 on natural gas volumes sold of $3.72 per Mcf represented an increase from the $2.99 per Mcf received in 2012, due largely to international instability and increased demand for cleaner-burning fuels. Concerns of continued oversupply and soft demand because of the slow economic recovery along with a warmer-than-average winter kept the price of natural gas from spiking too high.

Item 1A. Risk Factors

Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors; Lower prices could reduce the net proceeds payable to the Trust and Trust distributions.

The Trust’s monthly distributions are highly dependent upon the prices realized from the sale of crude oil and natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unit holders. Crude oil and natural gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust. Factors that contribute to price fluctuation include, among others:

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

• worldwide economic conditions;

• weather conditions;

• 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.

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;

13

• 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 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.

14

Cash held by the Trustee is not fully insured by the Federal Deposit Insurance Corporation, and future royalty income may be subject to risks related to the creditworthiness of third parties.

Currently, cash held by the Trustee as a reserve for liabilities and for the payment of expenses and distributions to Unit holders is invested in Bank of America certificates of deposit which are backed by the good faith of Bank of America, N.A., but are only insured by the Federal Deposit Insurance Corporation up to $250,000. Each Unit holder should independently assess the creditworthiness of Bank of America, N.A. For more information about the credit rating of Bank of America, N.A., please refer to its periodic filings with the SEC. The Trust does not lend money and has limited ability to borrow money, which the Trustee believes limits the Trust’s risk from the current tightening of credit markets. The Trust’s future royalty income, however, 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. Information contained in Bank of America, N.A.’s periodic filings with the SEC is not incorporated by reference into this annual report on Form 10-K and should not be considered part of this report or any other filing that the Trust makes with the SEC.

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 consecutive two-year period. Sale of all of the Royalty Properties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders.

Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights against the current or future operators developing the Royalty Properties.

The voting rights of a Unit holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit holders or for an annual or other periodic re-election of the Trustee.

The Trust Agreement and related trust law permit the Trustee and the Trust to take appropriate action against the operators developing the Royalty Properties to compel them to fulfill the terms of the conveyance of the Royalty Properties. If the Trustee does not take appropriate action to enforce provisions of the conveyance,

15

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.

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, 2013, which comments remain unresolved.

Item 2. Properties.

The assets of the Registrant consist principally of the Royalty Properties, which constitute interests in gross production of oil, gas and other minerals free of the costs of production. The Royalty Properties consist of royalty and mineral interests, including landowner’s royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and any other similar, nonparticipatory interest, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas. These properties are represented by approximately 5,400 tracts of land. Approximately 2,950 of the tracts are in Oklahoma, 1,750 in Texas, 330 in Louisiana, 200 in New Mexico, 150 in Mississippi and 12 in Florida.

The following table summarizes total developed and proved undeveloped acreage represented by the Royalty Properties at December 31, 2013.

	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

16

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, 2014 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 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. Paul J. Szatkowski, a Senior Vice President with DeGolyer and MacNaughton, was the primary engineer responsible for the report. Mr. Szatkowski’s qualifications are set forth in the Certificate of Qualification attached to the letter report below.

17

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 18, 2014

Bank of America N.A.

P. O. Box 830650

Dallas, Texas 75283-0650

Ladies and Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the net proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of January 1, 2014, of certain properties that Sabine Royalty Trust (the Trust) has represented that it owns. This evaluation was prepared for the purpose of reporting estimates of the Trust’s reserves and associated future net revenue. This evaluation was completed on February 18, 2014. The properties appraised consist of royalties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma, and Texas. Bank of America N.A. (Bank of America) acts as trustee of the Trust. Bank of America has represented that these properties account for 100 percent of revenues attributed to royalty interest payments received by the Trust as of January 1, 2014. The properties appraised account for 100 percent of the Trust’s proved reserves. The net proved 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 included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2013. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the Trust after deducting all interests owned by others.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as that portion of the total gas to be delivered into a gas pipeline for sale after separation, processing, fuel use, and flare. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at the legal pressure base of the state in which the interest is located. Condensate reserves estimated herein are those to be recovered by conventional lease separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

Values shown herein are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is that revenue which will accrue to the appraised interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated production taxes, ad valorem taxes, and expenses including, but not limited to, treating, compression and marketing expenses incurred on the Trust’s royalty interests from the future gross revenue. Future income tax expenses were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at a specified arbitrary discount rate compounded monthly over the expected period of realization.

Estimates of oil, condensate, NGL, and natural gas reserves and future net revenue should be regarded only as estimates that may change as further production history and additional information become available. Not only are such reserves and revenue 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.

18

Data used in this evaluation were obtained from reviews with Bank of America personnel, Bank of America files, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by IHS Global Inc.; Copyright 2014 IHS Global Inc. In the preparation of this report we have relied, without independent verification, upon such information furnished by Bank of America with respect to property interests owned by the Trust, 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.

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 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.

An analysis of reservoir performance, including production rate, reservoir pressure, and gas-oil ratio behavior, was used in the estimation of reserves. 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 or to the limit of the production licenses as appropriate.

In certain cases, when the previously named methods could not be used, reserves were estimated by analogy with similar wells or reservoirs for which more complete data were available.

The Trust owns several thousand royalty interests. In view of the limited information available to a royalty owner and the small reserves volumes attributable to many of these interests, certain of the reserves representing approximately 23 percent of the total net reserves of the properties included herein were summarized by state or field and estimated in the aggregate rather than on a property-by-property basis. Historical records of net production and revenue and experience with similar properties were used in evaluating these properties.

Undeveloped reserves were estimated for certain properties based on industry activity on and adjacent to these certain properties as well as other public knowledge concerning the future development of certain properties. These undeveloped reserves represent only 6 percent of the total net reserves evaluated herein.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. 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

19

conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves — Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves — Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

20

(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.

The extent to which probable and possible reserves ultimately may be recategorized as proved reserves is dependent upon future drilling, testing, and well performance. The degree of risk to be applied in evaluating probable and possible reserves is influenced by economic and technological factors as well as the time element. No probable or possible reserves have been evaluated for this report.

Primary Economic Assumptions

Revenue values in this report were estimated using the initial prices and expenses provided by Bank of America. The following economic assumptions were used for estimating existing and future prices and costs:

Oil, Condensate, NGL, and Natural Gas Prices

Oil, condensate, NGL, and natural gas prices are based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period. A West Texas Intermediate oil reference price of $96.90 per barrel and a Henry Hub gas reference price of $3.68 per million British thermal units were used for this evaluation. The prices were held constant thereafter and were not escalated for inflation.

Based on royalty receipts received by the Trust, as provided by Bank of America, various oil, condensate, NGL, and natural gas price differentials based on product quality and property location were determined for each property. These differentials were then applied to the above reference prices, respectively, to reflect the net wellhead prices anticipated to be received by each property.

The volume-weighted average prices attributable to estimated proved reserves over the lives of the properties were $92.11 per barrel of oil and condensate, $3.64 per thousand cubic feet of gas, and $35.07 per barrel of NGL.

Operating Expenses and Capital Costs

The properties appraised are royalties. Therefore, no operating expenses or capital costs are incurred. The expenses reported are primarily severance taxes and ad valorem taxes, which are based on historical tax rates furnished by Bank of America. Several properties incur additional expenses related to transportation, marketing, and/or other expenses that are charged to the royalty interests. These expenses are reported as transportation expenses. No escalation has been applied to the expenses.

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 oil and gas reserves, we are not aware of any such governmental actions which would restrict the recovery of the January 1, 2014, estimated oil and gas reserves. The reserves estimated in this report can be produced under current regulatory guidelines.

21

Our estimates of the Trust’s net proved reserves, as of January 1, 2014, attributable to the reviewed properties are based on the definitions of proved reserves of the SEC and are summarized by geographic area as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of January 1, 2014
	Proved Developed Reserves				Proved Undeveloped Reserves
State	Oil, Condensate,and NGL(Mbbl)		Sales Gas (MMcf)		Oil, Condensate, and NGL (Mbbl)		Sales Gas (MMcf)
Florida		57		0		0		0
Louisiana		73		391		5		0
Mississippi		131		483		41		0
New Mexico		457		2,399		0		0
Oklahoma		580		9,697		0		0
Texas		4,699		21,456		216		3,004
Total		5,997		34,426		262		3,004

A projection of the estimated future net revenue from the properties appraised, as of January 1, 2014, based on the aforementioned assumptions concerning prices and expenses is summarized as follows, expressed in thousands of dollars (M$):

Year Ending December 31	Future Net Revenue* (M$)
2014		45,675
2015		42,313
2016		38,329
Subtotal		126,317
Remaining		450,531
Total		576,848

* Future income tax expenses were not taken into account in the preparation of these estimates.

The present worth at a discount rate of 10 percent of future net revenue, as of January 1, 2014, is estimated to be M$258,163.

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, natural gas liquids, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries — Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the Financial Accounting Standards Board and Rules 4-10(a) (1)-(32) of Regulation S-X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S-K of the Securities and Exchange Commission; 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, (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year (January 1, 2013), and (iii) at the request of Bank of America and because of the limited availability of data, proved reserves, future net revenue therefrom, and the present worth values set forth herein for certain royalty interests accounting for approximately 23 percent of the Trust’s total proved net reserves have been estimated in the aggregate by state or area rather than on a property-by-property basis using net production and revenue data and our general knowledge of producing characteristics in the geographic areas in which such interests are located.

22

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.

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 letter report has been prepared at the request of Bank of America on behalf of the Trust. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

/s/ Paul J. Szatkowski, P.E.

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

23

CERTIFICATE of QUALIFICATION

I, Paul J. Szatkowski, 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 letter report addressed to Bank of America dated February 18, 2014, and that I, as Senior Vice President, was responsible for the preparation of this report.

2. That I attended Texas A&M University, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in 1974; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the International Society of Petroleum Engineers and the American Association of Petroleum Geologists; and that I have in excess of 39 years of experience in oil and gas reservoir studies and reserves evaluations.

/s/ Paul J. Szatkowski, P.E.

Paul J. Szatkowski, P.E.

Senior Vice President

DeGolyer and MacNaughton

24

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 2014 will be approximately $2,530,000.

The present value of future net revenue of the Trust’s proved developed reserves increased from $250,113,950 at January 1, 2013 to $258,163,043 at January 1, 2014. This increase resulted primarily from the oil and gas prices used in the calculation of such amount, from an average price of $90.08 per barrel of oil and $2.72 per Mcf of gas at January 1, 2013 to an average price of $92.11 per barrel of oil and $3.64 per Mcf of gas at January 1, 2014.

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 18, 2014, NYMEX posted oil prices were approximately $102.43 per barrel, which compared to the average posted price of $96.90 per barrel, used to calculate the worth of future net revenue of the Trust’s proved developed reserves, would result in a larger standardized measure of discounted future net cash flows for oil. As of February, 18, 2014, NYMEX posted gas prices were $5.55 per million British thermal units. The use of such price, as compared to the average posted price of $3.68 per million British thermal units, used to calculate the future net revenue for the Trust’s proved developed reserves would result in a larger standardized measure of discounted future net cash flows for gas.

The volatile nature of the world energy markets makes it difficult to estimate future prices of oil and gas. The prices obtained for oil and gas depend upon numerous factors, none of which is within the Trustee’s control, including the domestic and foreign supply of oil and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of pipeline capacity, instability in oil-producing regions and the effect of governmental regulations.

Item 3. Legal Proceedings.

There are no material pending legal proceedings to which the Registrant is a party or of which any of its property is the subject.

Item 4. Mine Safety Disclosures.

Not applicable.

25

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.” The following table sets forth the high and low sales prices for the Units and the aggregate amount of cash distributions paid by the Trust during the periods indicated.

	Sales Price				Distributions per Unit
2013	High		Low
First Quarter	$	48.59	$	39.94	$	0.83998
Second Quarter		55.00		46.13		1.03686
Third Quarter		53.95		50.01		1.06521
Fourth Quarter		53.16		49.50		0.97440

	Sales Price				Distributions per Unit
2012	High		Low
First Quarter	$	66.50	$	59.61	$	0.94948
Second Quarter		63.00		45.57		1.02602
Third Quarter		56.01		50.00		0.95908
Fourth Quarter		52.35		38.86		0.76632

At February 20, 2014, there were 14,579,345 Units outstanding and approximately 1,341 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	2013		2012		2011		2010		2009
Royalty Income	$	60,778,627	$	54,648,942	$	60,683,565	$	56,087,045	$	41,491,746
Distributable Income		58,719,392		52,320,222		58,559,410		53,976,491		39,246,196
Distributable Income per Unit		4.03		3.59		4.02		3.70		2.69
Total Assets at Year End		6,949,006		5,255,415		6,256,750		5,362,706		5,523,658
Distributions per Unit		3.92		3.70		3.97		3.70		2.79

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.

26

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 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 2011, 2012 and 2013.

Net royalty income during 2013 increased approximately $6,130,000, or 11.2 percent, compared to 2012 net royalty income, which had decreased approximately $6,035,000, or 9.9 percent, from 2011 net royalty income.

Revenues generated by sales of oil and gas increased in 2013 from 2012 as a result of higher gas prices ($5.5 million) and higher oil sales volumes ($3.6 million), offset somewhat by lower gas sales volumes ($2.1 million) and lower oil prices ($0.8 million)

Gas volumes decreased from 7,581,774 thousand cubic feet (“Mcf”) in 2012 to 7,015,254 Mcf in 2013 after increasing from 6,912,203 Mcf in 2011. The average price per Mcf of gas received by the Trust increased from $2.99 in 2012 to $3.72 in 2013 after decreasing from $4.36 in 2011. The Trustee believes that the negative trend in gas prices from 2011 to 2012 was due mostly to oversupply and a decreased demand due to a warmer-than-average winter in 2012 that drove natural gas prices down significantly for most of the year. The fourth quarter of 2012 showed a slight upturn in the price of natural gas that continued as a trend in 2013 due to largely to international instability and increased demand for cleaner-burning fuels.

Oil volumes sold increased to 474,095 barrels (“Bbls”) in 2013 from 432,454 Bbls in 2012, after having increased from 430,203 Bbls in 2011. The average sales price of oil decreased to $86.84 per Bbl in 2013, from $88.77 per Bbl in 2012, which was an increase from $87.22 per Bbl in 2011. 2011 was a volatile year, with the uncertainty of the European economy, political unrest, and a continued lackluster performance of the U.S. economy causing oil prices to fluctuate, but still trend upward. In 2012, a continued economic recovery and increased demand for oil made for higher prices than 2011. With the economy growing at an even slower pace in 2013, lower demand for oil caused the prices to decrease from the 2012 levels.

Interest income was $7,000 in 2013, unchanged from 2012, which had increased from $5,000 in 2011. Changes in interest income are the result of changes in interest rates and funds available for investment.

General and administrative expenses decreased to $2,066,000 in 2013 from $2,336,000 in 2012 due mainly to decreases in trustee/escrow agent fees of approximately $119,400; legal services of approximately $98,800, enginering services of approximately $25,400 and auditing fees of approximately $41,800. These decreases were

27

offset somewhat by increases in printing and unitholder information services of approximately $10,000, ad valorem rendition services of approximately $ 4,700 and professional services of approximately $5,300.

General and administrative expenses increased to $2,336,000 in 2012 from $2,129,000 in 2011 due mainly to increases in engineering services of approximately $65,800, legal services of approximately $46,800, trustee/escrow agent fees of approximately $32,100, auditing fees of approximately $25,000, and unitholder information services of approximately $27,400.

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 June 2013, the Trust received a refund of $376,838 from the State of Oklahoma and in September 2013, the Trust received a refund of $201,691 from the State of New Mexico. In June 2012, the Trust received a refund of $440,171 from the State of Oklahoma and in July 2012, the Trust received a refund of $210,765 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 July 2013, September 2013, July 2012 and August 2012 distributions, respectively.

Contractual Obligations

Contractual Obligations	Total		Less than 1 Year		1-3 Years		3-5 Years		More than 5 Years
Long-Term Debt Obligations		0		0		0		0		0
Capital Lease Obligations		0		0		0		0		0
Operating Lease Obligations		0		0		0		0		0
Purchase Obligations		0		0		0		0		0
Other Long-Term Liabilities Reflected on the Trusts Balance Sheet		0		0		0		0		0
Total		0		0		0		0		0

Critical Accounting Policies and Estimates

The Trust’s financial statements reflect the selection and application of accounting policies that require the Trust to make significant estimates and assumptions. The following are some of the more critical judgement areas in the application of accounting policies that currently affect the Trust’s financial condition and results of operations.

1. Basis of Accounting

The financial statements of the Trust are prepared on the following basis and are not intended to present financial position and results of operations in conformity with accounting principles generally accepted in the United States of America:

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

• 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.

28

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

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

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 the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future cash flows relating to proved oil and gas reserves. Numerous uncertainties are inherent in estimating volumes and the value of proved reserves and in projecting future production rates and the timing of development of non-producing reserves. Such reserve estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production may be substantially different from the reserve estimates. See Note 8 of the Notes to Financial Statements in Item 8 hereof for additional information regarding the proved oil and gas reserves of the Trust. Other than those filed with the SEC, our estimated reserves have not been filed with or included in any reports to any federal agency.

4. Contingencies

Contingencies related to the Royalty Properties that are unfavorably resolved would generally be reflected by the Trust as reductions to future royalty income payments to the Trust with corresponding reductions to cash distributions to Unit holders. The Trustee is aware of no such items as of December 31, 2013.

29

New Accounting Pronouncements

There are no new pronouncements that are expected to have a significant impact on the Trust’s financial statements.

Off-Balance Sheet Arrangements

As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Royalty Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses, and its actions have been limited to those activities. Therefore, the Trust has not engaged in any off-balance sheet arrangements.

Inflation

Prices obtained for oil and gas production depend upon numerous factors that are beyond the control of the Trust, including the extent of domestic and foreign production, imports of foreign oil, market demand, domestic and worldwide economic and political conditions, storage capacity and government regulations and tax laws. Prices for both oil and gas have fluctuated between 2011 and 2013. The following table presents the weighted average prices received per year by the Trust:

	Oil Per BBL		Gas Per Mcf
2013	$	86.84	$	3.72
2012		88.77		2.99
2011		87.22		4.36

Forward-Looking Statements

This Annual Report includes “forward-looking statements” within the meaning of Section 21E of the Securities Exchange Act of 1934, which are intended to be covered by the safe harbor created thereby. All statements other than statements of historical fact included in this Annual Report are forward-looking statements. Such statements include, without limitation, factors affecting the price of oil and natural gas contained in Item 1, “Business,” certain reserve information and other statements contained in Item 2, “Properties,” certain statements regarding the Trust’s financial position, industry conditions and other matters contained in this Item 7 and the satisfaction or waiver of conditions to the Trustee’s resignation contained in Item 1, “Business”. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report affecting oil and gas prices (including, without limitation, the domestic and foreign supply of oil and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of pipeline capacity, instability in oil-producing regions and the effect of governmental regulations), the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in Item 1A, “Risk Factors”.

30

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.

31

Item 8. Financial Statements and Supplementary Data.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Sabine Royalty Trust and

Bank of America, N.A., Trustee,

Dallas, Texas:

We have audited the accompanying statements of assets, liabilities, and trust corpus of Sabine Royalty Trust (the “Trust”) as of December 31, 2013 and 2012, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2013. 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 conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 2 to the financial statements, these financial statements have been 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.

In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of Sabine Royalty Trust at December 31, 2013 and 2012, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2013, on the basis of accounting described in Note 2.

We have also 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, 2013, based on the criteria established in Internal Control — Integrated Framework 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 3, 2014 expressed an unqualified opinion on the Trust’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Dallas, TX

March 3, 2014

32

SABINE ROYALTY TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus

	December 31,
	2013		2012
Assets
Cash and short-term investments	$	6,547,635	$	4,801,131
Royalty interests in oil and gas properties less accumulated amortization of $21,993,814 (2013) and $21,940,901 (2012)		401,371		454,284
Total	$	6,949,006	$	5,255,415
Liabilities and Trust Corpus
Trust expenses payable	$	112,760	$	200,902
Other payables (Note 4)		1,201,733		987,200
Total liabilities		1,314,493		1,188,102
Contingencies (Note 2)
Trust Corpus (14,579,345 units of beneficial interest authorized and outstanding)		5,634,513		4,067,313
Total	$	6,949,006	$	5,255,415

Statements of Distributable Income

	Year Ended December 31,
	2013		2012		2011
Royalty Income	$	60,778,627	$	54,648,942	$	60,683,565
Interest Income		6,772		6,957		5,267
Total		60,785,399		54,655,899		60,688,832
General and administrative expenses (Note 6)		2,066,007		2,335,677		2,129,422
Distributable income	$	58,719,392	$	52,320,222	$	58,559,410
Distributable income per unit (Basic and Assuming Dilution) (14,579,345 units) (Notes 1,2)	$	4.03	$	3.59	$	4.02

Statements of Changes in Trust Corpus

	2013			2012			2011
Trust corpus, beginning of year	$	4,067,313		$	5,754,313		$	5,086,272
Amortization of royalty interests		(52,913	)		(50,519	)		(67,204	)
Distributable income		58,719,392			52,320,222			58,559,410
Distributions to unit holders (Note 3)		(57,099,279	)		(53,956,703	)		(57,824,165	)
Trust corpus, end of year	$	5,634,513		$	4,067,313		$	5,754,313
Distributions per unit (Note 3)	$	3.92		$	3.70		$	3.97

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

33

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.

Bank of America, N.A. (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).

34

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management gave notice to Unit holders that it will be resigning as Trustee subject to the conditions set forth below. Bank of America, N.A. intends to nominate Southwest Bank, an independent state bank chartered under the laws of the State of Texas and headquartered in Fort Worth, Texas (“Southwest Bank”), as successor trustee at a meeting of Unit holders of the Trust to be called for the purpose of approving a successor trustee of the Trust. U.S. Trust, Bank of America Private Wealth Management’s resignation is conditioned on the satisfaction or waiver by U.S. Trust, Bank of America Private Wealth Management of each of the following: (i) the appointment of Southwest Bank as trustee of the Trust; (ii) the appointment of Southwest Bank or another successor trustee as trustee of six other royalty trusts for which U.S. Trust, Bank of America Private Wealth Management currently serves as trustee and as agent under a disbursing arrangement for which it currently serves as agent; (iii) the accuracy of certain representations and warranties and performance of certain agreements made by Southwest Bank in an agreement between U.S. Trust, Bank of America Private Wealth Management and Southwest Bank; and (iv) no governmental injunction, order or other action that would prohibit Southwest Bank’s appointment, U.S. Trust, Bank of America Private Wealth Management’s resignation or the other actions described above. The effective date of U.S. Trust, Bank of America Private Wealth Management’s resignation shall be May 30, 2014, assuming all of the conditions described above have been satisfied or waived as of such date.

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. On December 31, 2001, Bank of America, N.A. assumed the duties as Trustee of the Sabine Louisiana Royalty Trust, since Louisiana law now permits an out-of-state bank to act in this capacity. Therefore, the trust now only has one escrow agent, which is the Trustee, and a single escrow agreement.

Pursuant to the terms of the escrow agreement and the conveyances of the properties by Sabine, the proceeds of production from the Royalty Properties for each calendar month, and interest thereon, are collected by the escrow agent and are paid to and received by the Trust only on the next monthly record date. The escrow agent has agreed to endeavor to assure that it incurs and pays expenses and fees for each calendar month only on the next monthly record date. The Trust Agreement also provides that the Trustee is to endeavor to assure that income of the Trust will be accrued and received and expenses of the Trust will be incurred and paid only on each monthly record date. Assuming that the escrow agreement is recognized for federal income tax purposes and that the Trustee, as escrow agent is able to control the timing of income and expenses, as stated above, cash and accrual basis Unit holders should be treated as realizing income only on each monthly record date. The Trustee is treating the escrow agreement as effective for tax purposes. However, for financial reporting purposes, royalty and interest income are recorded in the calendar month in which the amounts are received by either the escrow agent or the Trust.

35

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.

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 the unit-of-production method. This amortization is shown as a reduction of Trust corpus.

• Distributions to Unit holders are recognized when declared by the Trustee (see Note 3).

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

• Royalty income is recognized in the month received 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, 2013.

36

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

Use of Estimates

The preparation of financial statements in conformity with the basis of accounting described above requires management to make estimates and assumptions that affect reported amounts of certain assets, liabilities, revenues and expenses as of and for the reporting periods. Actual results may differ from such estimates.

Impairment

The Trustee routinely reviews its royalty interests in oil and gas properties for impairment whenever events or circumstances indicate that the carrying amount of an asset may not be recoverable. If an impairment event occurs and it is determined that the carrying value of the Trust’s royalty interests may not be recoverable, an impairment will be recognized as measured by the amount by which the carrying amount of the royalty interests exceeds the fair value of these assets, which would likely be measured by discounting projected cash flows. There is no impairment of the assets as of December 31, 2013.

New Accounting Pronouncements

There are no new pronouncements that are expected to have a significant impact on the Trust’s financial statements.

Distributable Income Per Unit

Basic distributable income per Unit is computed by dividing distributable income by the weighted average Units outstanding. Distributable income per Unit assuming dilution is computed by dividing distributable income by the weighted average number of Units and equivalent Units outstanding. The Trust had no equivalent Units outstanding for any period presented. Therefore, basic distributable income per Unit and distributable income per Unit assuming dilution are the same.

Federal Income Taxes

The Internal Revenue Service has ruled that the Trust is classified as a grantor trust for federal income tax purposes and therefore is not subject to taxation at the trust level. The Unit holders are considered, for federal income tax purposes, to own the Trust’s income and principal as though no trust were in existence. Accordingly, no provision for federal income tax expense has been made in these financial statements. The income of the Trust will be deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust, which is on the record date following the end of each month, as discussed above in Note 1.

Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America, Private Wealth Management, EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, email address trustee@sbr-sabineroyalty.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabineroyalty.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.

37

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 June 2013, the Trust received a refund of $376,838 from the State of Oklahoma and in September 2013, the Trust received a refund of $201,691 from the State of New Mexico. In June 2012, the Trust received a refund of $440,171 from the State of Oklahoma and in July 2012, the Trust received a refund of $210,765 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 July 2013, September 2013, July 2012 and August 2012 distributions, respectively.

4. Other Payables

Other payables consist of the following:

December 31,	2013		2012
Royalty receipts in suspense pending verification of ownership interest or title	$	1,201,733	$	987,200

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.

5. Subsequent Events

Distributions

Subsequent to December 31, 2013, the Trust declared the following distributions:

Notification Date	Monthly Record Date	Payment Date	Distribution per Unit
January 3, 2014	January 15, 2014	January 29, 2014	$	.36228
February 5, 2014	February 18, 2014	February 28, 2014	$	.27200

38

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:

	2013		2012		2011
Trustee’s fee		$295,294		$325,148		$317,119
Escrow agent’s fee		885,863		975,435		951,336
Professional fees		328,355		497,309		363,749
Unit holders’ services fees		346,003		339,634		306,469
Other		210,492		198,151		190,749
Total General and Administrative Expenses		$2,066,007		$2,335,677		$2,129,422

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, 2013 and 2012 (in thousands, except per Unit amounts):

2013	Royalty Income		Distributable Income		Distributable Income per Unit
First Quarter	$	15,502	$	15,008	$	1.03
Second Quarter		13,857		13,137		0.90
Third Quarter		17,245		16,831		1.15
Fourth Quarter		14,175		13,743		0.95
	$	60,779	$	58,719	$	4.03

2012	Royalty Income		Distributable Income		Distributable Income per Unit
First Quarter	$	15,211	$	14,651	$	1.00
Second Quarter		15,108		14,300		0.98
Third Quarter		12,355		11,919		0.82
Fourth Quarter		11,975		11,450		0.79
	$	54,649	$	52,320	$	3.59

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.

39

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, 2011		5,573			36,891
Revisions of previous statements		616			5,120
Production		(368	)		(5,628	)
December 31, 2011		5,821			36,383
Revisions of previous statements		1,061			11,679
Production		(383	)		(6,412	)
December 31, 2012		6,499			41,650
Revisions of previous statements		156			1,247
Production		(396	)		(5,467	)
December 31, 2013		6,259			37,430

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

	Oil		Gas
	(Barrels)		(Mcf)
Proved developed reserves:
January 1, 2011		5,368		33,428
December 31, 2011		5,662		33,368
December 31, 2012		6,296		38,642
December 31, 2013		5,997		34,426

40

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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 ($96.90 per bbl and $3.68 per MMBtu, respectively) during the 12-month period prior to the fiscal year-end, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions and severance and ad valorem taxes, if any, and economic conditions, discounted at 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 $92.11 per barrel and $3.64 per Mcf. The impact of changes in current prices on reserves could vary significantly from year to year. Accordingly, the information presented below should not be viewed as an estimate of the fair market value of the Trust’s oil and gas properties nor should it be viewed as indicative of any trends.

December 31,	2013			2012			2011
Future net cash inflows	$	576,848		$	570,344		$	565,686
Discount of future net cash flows @ 10%		(318,685	)		(320,230	)		(308,565	)
Standardized measure of discounted future net cash inflows	$	258,163		$	250,114		$	257,121

The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2013, 2012 and 2011 is as follows (in thousands):

	2013			2012			2011
Standardized measure of discounted future net cash flows, January 1,	$	250,114		$	257,121		$	227,838
Royalty income, net of severance and ad valorem taxes		(60,779	)		(54,649	)		(60,684	)
Changes in prices, net of related costs		17,397			(25,071	)		34,172
Revisions of previous estimates and other		26,420			47,001			33,011
Accretion of discount		25,011			25,712			22,784
Standardized measure of discounted future net cash flows, December 31,	$	258,163		$	250,114		$	257,121

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 18, 2014, NYMEX posted oil prices were approximately $102.43 per barrel, which compared to the average posted price of $96.90 per barrel, used to calculate the worth of future net revenue of the Trust’s proved developed reserves, would result in a larger standardized measure of discounted future net cash flows for oil. As of February, 18, 2014, NYMEX posted gas prices were $5.55 per million British thermal units. The use of such price, as compared to the average posted price of $3.68 per million British thermal units, used to calculate the future net revenue for the Trust’s proved developed reserves would result in a larger standardized measure of discounted future net cash flows for gas.

41

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

9. State Taxes

Texas does not impose an income tax. Therefore, no part of the income produced by the Trust is subject to an income tax in Texas. However, Texas imposes a franchise tax at a rate of 1% 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 considered a taxable entity under the Texas franchise tax would generally be required to include its share of Trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code providing that such income is sourced according to the location of the day-to-day operations of the Trust, which is Texas.

Because the Trust distributes all of its net income to Unit holders, it should not be subject to income tax in Louisiana, Florida, Mississippi, New Mexico or Oklahoma. While the Trust should not owe tax, Unit holders may have a state filing responsibility in each of those states.

Unit holders should consult their own tax advisors regarding state tax requirements, if any, applicable to ownership of Trust Units.

*****

42

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 2013 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

Trustee’s Report on Internal Control Over Financial Reporting

The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities Exchange Act of 1934, as amended. Internal control over financial reporting is a process to provide reasonable assurance regarding the reliability of financial reporting for external purposes in accordance with the modified cash basis of accounting. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting based on the criteria established in Internal Control — Integrated Framework 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control — Integrated Framework 1992, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2013. The independent registered public accounting firm of Deloitte & Touche LLP, as auditors of the statements of assets, liabilities, and trust corpus, and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2013, has issued an attestation report on the Trust’s internal control over financial reporting, which is included herein.

43

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Unit Holders of Sabine Royalty Trust and

Bank of America, N.A., Trustee

Dallas, Texas:

We have audited the internal control over financial reporting of Sabine Royalty Trust (the “Trust”) as of December 31, 2013, based on criteria established in Internal Control — Integrated Framework 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A trust’s internal control over financial reporting is a process designed by, or under the supervision of, the Trustee, or persons performing similar functions, and effected by the Trustee, 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, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America and is described in Note 2 to the Trust’s financial statements. A trust’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 trust; (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 discussed above, and that receipts and expenditures of the Trust are being made only in accordance with authorizations of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Trust’s assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Sabine Royalty Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2013, based on the criteria established in Internal Control —Integrated Framework 1992 issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus of the Trust as of December 31, 2013 and the related statements of distributable income and changes in trust corpus for the year ended December 31, 2013, which financial statements have been prepared on the modified cash basis of accounting as described in Note 2 to such financial statements, and our report dated March 3, 2014 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Dallas, TX

March 3, 2014

44

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, U.S. Trust, Bank of America Private Wealth Management, must comply with the bank’s code of ethics, a copy of which will be made available to Unit holders without charge, upon request by appointment at Bank of America Plaza, 17th Floor, 901 Main Street, Dallas, Texas, 75202.

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 14, 2014, 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) Fayez Sarofim reported as of December 31, 2011, he directly and through certain affiliated entities 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. Bank of America, N.A., the Trustee, held as of February 4, 2014 an aggregate of 228,875 Units in various fiduciary capacities, and it had shared voting and investment power with respect to 128,838 of such Units.

(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.

45

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 for the years ended December 31, 2013 and 2012 are:

	2013		2012
Audit fees	$	106,700	$	148,500
Audit-related fees	$	0	$	0
Tax fees	$	16,000	$	24,200
All other fees	$	0	$	0

As referenced in Item 10, above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP.

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)

Report of Independent Registered Public Accounting Firm

Statements of Assets, Liabilities and Trust Corpus at December 31, 2013 and 2012

Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2013

Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2013

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.
(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.
(23)		–	Consent of DeGolyer and MacNaughton.
(31)		–	Rule 13a-14(a)(15d-14(a)) Certification.
(32)		–	Certification by Bank of America, Trustee of Sabine Royalty Trust, dated March 3, 2014 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
(99.1)		–	Report dated February 10, 2014 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2013.
(99.2)		–	Report dated March 3, 2014 of the Statement of Fees and Expenses paid by Sabine Royalty Trust to Bank of America, N.A., as Trustee and Escrow Agent.

* Exhibits 4(a) and 4(b) are incorporated herein by reference to Exhibits 4(a) and 4(b), respectively, of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993.

46

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: BANK OF AMERICA, N.A., Trustee
By:	/s/    RON E. HOOPER
	Ron E. Hooper Senior Vice-President

Date: March 3, 2014

(The Registrant has no directors or executive officers.)

47

INDEX TO EXHIBITS

Exhibit Number			Description
	(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.
	(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.
	(23)	–	Consent of DeGolyer and MacNaughton.
	(31)	–	Rule 13a-14(a)(15d-14(a)) Certification.
	(32)	–	Certification by Bank of America, Trustee of Sabine Royalty Trust, dated March 3, 2014 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
	(99.1)	–	Report dated February 10, 2014 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2013.
	(99.2)	–	Report dated March 3, 2014 of the Statement of Fees and Expenses paid by Sabine Royalty Trust to Bank of America, N.A., as Trustee and Escrow Agent.

* Exhibits 4(a) and 4(b) are incorporated herein by reference to Exhibits 4(a) and 4(b), respectively, of the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993.

EX-23

EXHIBIT 23

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

February 25, 2014

Sabine Royalty Trust

Bank of America, N.A.

Bank of America Plaza - 17th Floor

901 Main Street

Dallas, Texas 75202

Gentlemen:

We hereby consent to the inclusion of our third party letter report dated February 18, 2014, containing our opinion on the proved reserves and revenue, as of January 1, 2014, of certain royalty interests owned by Sabine Royalty Trust in the Annual Report on Form 10–K for the year ended December 31, 2013, of the Sabine Royalty Trust (the Form 10-K) to be filed with the United States Securities and Exchange Commission. We also consent to the references to DeGolyer and MacNaughton under “Properties—Reserves” in Item 2 and under “Supplemental Oil and Gas Information (Unaudited)—Reserve Quantities” in Item 8 of the Form 10–K.

Very truly yours,

/s/    DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-31

EXHIBIT 31

CERTIFICATIONS

I, Ron Hooper, certify that:

1. I have reviewed this annual report on Form 10-K of Sabine Royalty Trust, for which Bank of America, N.A. acts as Trustee;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report;

4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)), or for causing such controls and procedures to be established and maintained, for the registrant and I have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any changes in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal control over financial reporting.

Date: March 3, 2014

By:	/s/    Ron E. Hooper
	Ron E. Hooper
	Senior Vice President and Trust Administrator
	Bank of America, N.A.

EX-32

EXHIBIT 32

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT

TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Sabine Royalty Trust (the “Trust”) on Form 10-K for the annual period ended December 31, 2013 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, not in its individual capacity but solely as the trustee of the Trust, certifies pursuant to 18 U.S.C. 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to its knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

BANK OF AMERICA, N.A., TRUSTEE FOR

SABINE ROYALTY TRUST

	By:	/s/    Ron E. Hooper
		Ron E. Hooper,
Date: March 3, 2014		Senior Vice President, Royalty Management

A signed original of this written statement required by Section 906 has been provided to Sabine Royalty Trust and will be retained by Sabine Royalty Trust and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

TAX INFORMATION

2013

This booklet contains tax information relevant to ownership of

Units of Sabine Royalty Trust and should be retained.

(This page intentionally left blank.)

SABINE ROYALTY TRUST

February 10, 2014

To Unit Holders:

This booklet provides 2013 tax information, which will allow you to determine your pro rata share of income and deductions attributable to your investment in Sabine Royalty Trust (the “Trust”). Each Unit holder is encouraged to read the entire booklet very carefully.

The material included in this booklet enables you to compute the information to be included in your federal and state income tax returns, and the items of income, deduction, and any other information shown in this booklet must be taken into account in computing your taxable income and credits on your federal income tax return and any state tax returns. This booklet, as well as any Forms 1099-MISC received from the Trust relating to backup withholding (discussed on page 3) and any IRS Forms 1099 and written tax statements issued by certain middlemen (discussed in more detail on pg. A-1) that hold Trust Units on your behalf, are the only information sources for Unit holders to determine their share of the items of income and expense of the Trust for the entire 2013 calendar year. Unit holders should retain this booklet and any Forms 1099 and written tax statements received from middlemen and any Forms 1099-MISC received from the Trust as part of their tax records.

The material herein is not intended and should not be construed as professional tax or legal advice. Each Unit holder should consult the Unit holder’s own tax advisor regarding all tax compliance matters relating to the Units.

To ensure compliance with Treasury Department Circular 230, Unit holders are hereby notified that any discussion of U.S. federal income tax issues in this booklet is not intended or written to be relied upon, and cannot be relied upon, by Unit holders for the purpose of avoiding penalties that may be imposed on such Unit holders under the Internal Revenue Code of 1986.

For your convenience, simple revenue/expense and cost depletion calculators are now available on the Sabine Royalty Trust website at: www.sbr-sabineroyalty.com, on both the “Home” page and “Tax Information” page.

Very truly yours,

Sabine Royalty Trust,

By U.S. Trust, Bank of America Private Wealth Management, Trustee

1-800-365-6541

901 Main St. 17th Floor

Dallas, TX 75202

EIN 75-6297143

CUSIP 78568810

SABINE ROYALTY TRUST

TABLE OF CONTENTS

	Page
2013 TAX INFORMATION
Reading the Income and Expense Schedules		1
Identifying Which Income and Expense Schedules to Use		1
Applying the Data From the Income and Expense Schedules		1
Computing Depletion		2
Asset Sales and Dispositions		3
Redemptions		3
Sale or Exchange of Units		3
Classification of Investment		3
Nonresident Foreign Unit Holders		3
Unrelated Business Taxable Income		3
Net Investment Income Tax		3
Backup Withholding		4
State Tax		4
Table of 2013 Monthly Record Dates and Cash Distributions Per Unit		4
Tax Information Schedules
Form 1041, Grantor Trust for Calendar Year 2013		5
Supplemental Tax Table I—Gross Royalty Income Federal		6
Supplemental Tax Table II—Severance Tax Federal		6
Supplemental Tax Table III—Interest Income Federal		7
Supplemental Tax Table IV—Trust Administrative Expense Federal		7
Supplemental Tax Tables A through D Texas		8
Supplemental Tax Tables A through C Oklahoma		9
Supplemental Tax Tables A through C Florida		10
Supplemental Tax Tables A through C Louisiana		11
Supplemental Tax Tables A through C Mississippi		12
Supplemental Tax Tables A through C New Mexico		13
Depletion Schedule D-I		14
Depletion Schedule D-II		14
Depletion Schedule D-III		15
Depletion Schedule D-IV		16
Sample Tax Forms for Individual Unit Holders		17
Tax Computation Worksheets		21
Comprehensive Examples		22
Sabine Royalty Trust Historical Tax Worksheet		25
DISCUSSION OF TAX CONSIDERATIONS PERTAINING TO THE OWNERSHIP OF UNITS IN SABINE ROYALTY TRUST
Tax Background and WHFIT Information		A-1
Effect of Escrow Arrangement		A-2
Depletion		A-2
Cost Depletion		A-2
Percentage Depletion		A-3
Adjustment to Basis		A-3
Non-Passive Activity Income, Credits and Loss		A-3
Revenue/Expense and Depletion Calculators		A-3
Nonresident Foreign Unit Holders		A-3
Sale or Exchange of Units		A-4
Backup Withholding		A-4
State Tax		A-5
List of states’ contact information		A-7
(SRT 2013 TAX)

SABINE ROYALTY TRUST

2013 TAX INFORMATION

Reading the Income and Expense Schedules

The accompanying income and expense schedule and tables reflect tax information attributable to Sabine Royalty Trust (the “Trust”) for 2013. This information has been assembled on a per Unit basis and is expressed in decimal fractions of one dollar. A cumulative schedule for the twelve months ended December 31, 2013 and separate cumulative tables at the federal level as well as tables for each of the states in which the Trust has properties are included. Separate depletion schedules are enclosed that provide the necessary information for Unit holders to compute cost and percentage depletion with respect to their interests in the Trust.

Identifying Which Income and Expense Schedules to Use

Pursuant to the terms of the Trust agreement and the escrow agreement (discussed below on page A-2), the Trust receives income and incurs expenses only on the Monthly Record Dates listed on page 4. Furthermore, only Unit holders of record on Monthly Record Dates are entitled to cash distributions. On the basis of these agreements, both cash and accrual basis Unit holders should be considered as realizing income and incurring expenses only on Monthly Record Dates. Therefore, if you were not the Unit holder of record on a specified Monthly Record Date, you should not use the tax information for the month in which that Monthly Record Date falls. A table of Monthly Record Dates and cash distributions per Unit is included on page 4.

The appropriate schedules to be used by a Unit holder will depend upon (i) the date the Unit holder became a holder of record of the Units, (ii) if applicable, the date the Unit holder ceased to be the holder of record of the Units, and (iii) the tax year-end of the Unit holder. For instance, a Unit holder reporting on the calendar year basis who acquired Units and became a Unit holder of record on June 17, 2013 and who still owned only those Units on December 16, 2013 must use the federal and individual state, where applicable, tables to determine their proportionate income and expenses (located on pages 6-13), and Depletion Schedules D-I and D-II or Depletion Schedule D-IV, as appropriate (located on pages 14 and 16, respectively) for such Units. However, Unit holders reporting on a calendar year basis who became Unit holders of record prior to January 15, 2013 and who continued to own only those Units on December 16, 2013, can use either the cumulative schedule for calendar year 2013 (located on page 5) or the tables (located on pages 6-13) and Depletion Schedule D-III (located on page 15) or Depletion Schedule D-IV (located on page 16), as appropriate. As discussed in more detail herein, Unit holders may be entitled to a deduction for either cost depletion or percentage depletion (but not both), depending upon each Unit holder’s individual facts relating to the ownership of Trust Units.

Applying the Data From the Income and Expense Schedules

Unit holders who must use the separate income and expense tables should read the tables in the following manner: the months on the left-hand side of each table denote the month in which a Unit holder first became a Unit holder of record in 2013. Reading across from that month, choose the last month in 2013 in which the Unit holder was a holder of record with respect to those Units. Multiply that factor by the number of Units held for that specific period of time. For example, if Units were purchased on May 1, 2013 and held until December 31, 2013, a Unit holder would choose May from the left-hand side of the table and then choose the factor located under “December” from that row. For a worksheet approach to computing a Unit holder’s income and expense amounts, see the Tax Computation Worksheet on page 21.

(SRT 2013 TAX)

1

Computing Depletion

Depletion schedules are included that provide information for Unit holders to compute cost depletion and percentage depletion deductions with respect to their interests in the Trust. To compute cost depletion for any taxable period, Unit holders should multiply the cost depletion factor indicated on the relevant schedule times their original tax basis in the respective Unit(s) as reduced by the cost depletion and percentage depletion that was allowable as a deduction (whether or not deducted) in prior calendar years during which they owned the Units.

For your convenience, a simple cost depletion calculator is now available on the Sabine Royalty Trust website at: www.sbr-sabineroyalty.com, on both the “Home” page and “Tax Information” page.

A factor for percentage depletion is also included on Depletion Schedule D-IV. A Unit holder may be entitled to a percentage depletion deduction, in lieu of a cost depletion deduction, if percentage depletion exceeds cost depletion for any taxable period. To compute percentage depletion for any taxable period, Unit holders should multiply the appropriate percentage depletion factor indicated on Depletion Schedule D-IV by the number of Units owned by such Unit holder. 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 Trust properties generate gross income.

As discussed at page A-2 in the back portion of this booklet, the composite cost depletion factors are determined on the basis of a weighted average ratio of current production from each Trust property to the estimated future production from such property. This method of weighting the cost depletion factors permits the presentation of a single cost depletion factor for all Unit holders acquiring Units during a period in which there is no substantial change in the relative fair market values of the Trust properties. Primarily as a result of the decline in oil prices that occurred during 1986, there was a change in the relative fair market values of the Trust properties. Accordingly, two mutually exclusive cost depletion computations are included herein reflecting the composite cost depletion factors required to compute cost depletion for Units acquired in 1986.

The proper cost depletion schedule to use in computing 2013 cost depletion depends on the date when the Units were acquired, as described below. Therefore, Unit holders are encouraged to maintain records indicating the date of acquisition and the acquisition price for each Unit or lot of Units acquired.

Unit holders taking a cost depletion deduction who acquired Units before 2013 should use Depletion Schedule D-III (located on page 15). The federal cost depletion factors in Depletion Schedule D-III are presented on a cumulative basis for 2013. Depletion Schedule D-III contains no state-specific cost depletion factors. Unit holders should refer to Depletion Schedule D-II (located on page 14) for the state-specific cost depletion factors.

Unit holders who acquired Units in 2013 should use Depletion Schedule D-I (located on page 14). The federal cost depletion factors in Depletion Schedule D-I are presented on a cumulative and noncumulative basis for 2013. Depletion Schedule D-I contains no state-specific cost depletion factors. Unit holders should refer to Depletion Schedule D-II (located on page 14) for the state-specific cost depletion factors.

Depletion Schedule D-II (located on page 14) contains state-specific cost depletion factors, which are presented on a noncumulative basis for all years. These factors are appropriate for use in calculating the 2013 cost depletion allowance for Units purchased in all years. You may calculate state cost depletion by either (a) calculating the amount of state depletion for each month and adding together the monthly depletion amounts or (b) adding together the applicable monthly depletion factors for the relevant state to create a composite depletion factor for such state and, in both cases, multiplying that factor by the adjusted basis of your Units. Both methods should produce the same result.

(SRT 2013 TAX)

2

Asset Sales and Dispositions

There have been no sales or dispositions of Trust assets during the year.

Redemptions

There have been no redemptions of Trust interests during the year.

Sale or Exchange of Units

A discussion concerning the tax consequences associated with the sale or exchange of Units is presented on page A-4 in the back portion of this booklet.

Classification of Investment

Tax reform measures enacted in 1986 and 1987 require items of income and expense to be categorized as “passive,” “active” or “portfolio” in nature. An explanation of how these rules apply to the items of income and expense reported by the Trust is on page A-1 in the back portion of this booklet.

Nonresident Foreign Unit Holders

Nonresident alien individual and foreign corporation Unit holders (“Foreign Taxpayer(s)”) are subject to special tax rules with respect to their investments in the Trust. These rules are outlined on page A-3 in the back portion of this booklet.

Unrelated Business Taxable Income

Certain organizations that are generally exempt from federal income tax under Internal Revenue Code Section 501 are subject to federal income tax on certain types of business income defined in Section 512 as unrelated business taxable income (“UBTI”). The income of the Trust as to any tax-exempt organization should not be UBTI so long as the Trust Units are not “debt-financed property” within the meaning of Section 514(b) of the Internal Revenue Code. In general, a Trust Unit would be debt-financed if the Trust incurs debt or if the tax-exempt organization that is a Trust Unit holder incurs debt to acquire a Trust Unit or otherwise incurs or maintains a debt that would not have been incurred or maintained if the Trust Unit had not been acquired. A real property exception applies to the debt-financed property rules for certain types of exempt organizations. Consult your tax advisor if applicable.

Net Investment Income Tax

Section 1411 of the Code imposes a 3.8% Medicare tax on certain investment income earned by individuals, estates, and trusts for taxable years beginning after December 31, 2012. For these purposes, investment income generally will include a Unit holder’s allocable share of the Trust’s interest and royalty income plus the gain recognized from a sale of Trust Units. In the case of an individual, the tax is imposed on the lesser of (i) the individual’s net investment income from all investments, or (ii) the amount by which the individual’s modified adjusted gross income exceeds specified threshold levels depending on such individual’s federal income tax filing status ($250,000 for married persons filing a joint return and $200,000 in most other cases). 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 ($7,500 for 2013).

(SRT 2013 TAX)

3

Backup Withholding

Unit holders, other than Foreign Taxpayers, who have had amounts withheld in 2013 pursuant to the federal backup withholding provisions should have received a Form 1099-MISC from the Trust. The Form 1099-MISC reflects the total federal income tax withheld from distributions. Unlike other Forms 1099 that you may receive, the amount reported on the Form 1099-MISC received from the Trust should not be included as additional income in computing taxable income, as such amount is already included in the per Unit income items on the income and expense schedules included herein. The federal income tax withheld, as reported on the Form 1099-MISC, should be considered as a credit by the Unit holder in computing any federal income tax liability. Individual Unit holders should include the amount of backup withholding in the “Payments” section of the Unit holder’s 2013 Form 1040. For a further discussion of backup withholding, see page A-5 in the back portion of this booklet. For amounts withheld from Foreign Taxpayers, see page A-3 in the back portion of this booklet.

State Tax

Because the Trust holds royalty interests and receives income that is attributable to properties located in various states, Unit holders may be obligated to file a return and may have a tax liability in those states in addition to their state of residence. The accompanying tables have been prepared in such a manner that income and deductions attributable to the various states may be determined by each Unit holder. State tax matters are more fully discussed on page A-5 in the back portion of this booklet.

Table of 2013 Monthly Record Dates and Cash Distributions Per Unit

Unit holders, as reflected in the transfer books of the Trust on a Monthly Record Date, received the following per Unit cash distributions for 2013. The per Unit cash distributions reflected below have not been reduced by any taxes that may have been withheld from distributions to Foreign Taxpayers or from distributions to Unit holders subject to the federal backup withholding rules. The distribution checks were dated and mailed on the corresponding Date Payable.

Monthly Record Date	Date Payable	Distribution Per Unit
January 15, 2013	January 29, 2013	0.25115
February 15, 2013	February 28, 2013	0.33442
March 15, 2013	March 29, 2013	0.25441
April 15, 2013	April 29, 2013	0.44058
May 15, 2013	May 29, 2013	0.35200
June 17, 2013	June 28, 2013	0.24428
July 15, 2013	July 29, 2013	0.30479
August 15, 2013	August 29, 2013	0.44969
September 16, 2013	September 30, 2013	0.31073
October 15, 2013	October 29, 2013	0.39401
November 15, 2013	November 29, 2013	0.36308
December 16, 2013	December 30, 2013	0.21731

(SRT 2013 TAX)

4

Cumulative 2013

SABINE ROYALTY TRUST

EIN 75-6297143

FORM 1041, GRANTOR TRUST

Federal and State Income Tax Information

See Instructions for Use

SECTION I

INCOME AND EXPENSE PER UNIT

	ROYALTY INCOME AND EXPENSE						OTHER INCOME AND EXPENSE
Source	Gross Income		Severance Tax		Net Royalty Payments		Interest Income		Administrative Expense
Florida	$	.056487	$	0.002584	$	.053903	$	*	$	.002073
Louisiana		.094518		0.009844		.084674		*		.003100
Mississippi		.139124		0.008114		.131010		*		.004719
New Mexico		.305221		0.030639		.274582		*		.010253
Oklahoma		.647335		0.062583		.584752		*		.021573
Texas		3.132327		0.199538		2.932789		.000727		.104219
TOTAL	$	4.375012	$	0.313302	$	4.061710	$	.000727	$	.145937

SECTION II

RECONCILIATION OF CASH DISTRIBUTIONS PER UNIT

	Item	AMOUNT
1.	Total Net Royalty Payments	$	4.061710
2.	Interest Income		.000727
3.	Administrative Expense		(.145937	)
4.	Cash Distribution Per Unit**	$	3.916500

* Revenue attributable to these states was invested and earned interest income. Since the investments were made in Dallas, Texas, and the interest was paid there, such interest is included in the Texas interest income.

** Includes amounts withheld by the Trust from distributions to nonresident alien individuals and foreign corporations and remitted directly to the United States Treasury. This also includes amounts withheld pursuant to the backup withholding provisions.

(SRT 2013 TAX)

5

SABINE ROYALTY TRUST FEDERAL

Table I: 2013 Gross Royalty Income (Cumulative $ per Unit)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
JANUARY		0.288020		0.668600		0.954350		1.443271		1.850938		2.142389		2.479443		2.971348		3.314085		3.734755		4.131333		4.375012
FEBRUARY		—		0.380580		0.666330		1.155251		1.562918		1.854369		2.191423		2.683328		3.026065		3.446735		3.843313		4.086992
MARCH		—		—		0.285750		0.774671		1.182338		1.473789		1.810843		2.302748		2.645485		3.066155		3.462733		3.706412
APRIL		—		—		—		0.488921		0.896588		1.188039		1.525093		2.016998		2.359735		2.780405		3.176983		3.420662
MAY		—		—		—		—		0.407667		0.699118		1.036172		1.528077		1.870814		2.291484		2.688062		2.931741
JUNE		—		—		—		—		—		0.291451		0.628505		1.120410		1.463147		1.883817		2.280395		2.524074
JULY		—		—		—		—		—		—		0.337054		0.828959		1.171696		1.592366		1.988944		2.232623
AUGUST		—		—		—		—		—		—		—		0.491905		0.834642		1.255312		1.651890		1.895569
SEPTEMBER		—		—		—		—		—		—		—		—		0.342737		0.763407		1.159985		1.403664
OCTOBER		—		—		—		—		—		—		—		—		—		0.420670		0.817248		1.060927
NOVEMBER		—		—		—		—		—		—		—		—		—		—		0.396578		0.640257
DECEMBER		—		—		—		—		—		—		—		—		—		—		—		0.243679

Table II: 2013 Severance Tax (Cumulative $ per Unit)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
JANUARY		0.023118		0.056975		0.079079		0.115088		0.148565		0.176538		0.200788		0.233862		0.256147		0.273257		0.296997		0.313302
FEBRUARY		—		0.033857		0.055961		0.091970		0.125447		0.153420		0.177670		0.210744		0.233029		0.250139		0.273879		0.290184
MARCH		—		—		0.022104		0.058113		0.091590		0.119563		0.143813		0.176887		0.199172		0.216282		0.240022		0.256327
APRIL		—		—		—		0.036009		0.069486		0.097459		0.121709		0.154783		0.177068		0.194178		0.217918		0.234223
MAY		—		—		—		—		0.033477		0.061450		0.085700		0.118774		0.141059		0.158169		0.181909		0.198214
JUNE		—		—		—		—		—		0.027973		0.052223		0.085297		0.107582		0.124692		0.148432		0.164737
JULY		—		—		—		—		—		—		0.024250		0.057324		0.079609		0.096719		0.120459		0.136764
AUGUST		—		—		—		—		—		—		—		0.033074		0.055359		0.072469		0.096209		0.112514
SEPTEMBER		—		—		—		—		—		—		—		—		0.022285		0.039395		0.063135		0.079440
OCTOBER		—		—		—		—		—		—		—		—		—		0.017110		0.040850		0.057155
NOVEMBER		—		—		—		—		—		—		—		—		—		—		0.023740		0.040045
DECEMBER		—		—		—		—		—		—		—		—		—		—		—		0.016305

(SRT 2013 TAX)

6

SABINE ROYALTY TRUST FEDERAL

Table III: 2013 Interest Income (Cumulative $ per Unit)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
JANUARY		0.000038		0.000083		0.000111		0.000162		0.000207		0.000248		0.000285		0.000321		0.000372		0.000634		0.000685		0.000727
FEBRUARY		—		0.000045		0.000073		0.000124		0.000169		0.000210		0.000247		0.000283		0.000334		0.000596		0.000647		0.000689
MARCH		—		—		0.000028		0.000079		0.000124		0.000165		0.000202		0.000238		0.000289		0.000551		0.000602		0.000644
APRIL		—		—		—		0.000051		0.000096		0.000137		0.000174		0.000210		0.000261		0.000523		0.000574		0.000616
MAY		—		—		—		—		0.000045		0.000086		0.000123		0.000159		0.000210		0.000472		0.000523		0.000565
JUNE		—		—		—		—		—		0.000041		0.000078		0.000114		0.000165		0.000427		0.000478		0.000520
JULY		—		—		—		—		—		—		0.000037		0.000073		0.000124		0.000386		0.000437		0.000479
AUGUST		—		—		—		—		—		—		—		0.000036		0.000087		0.000349		0.000400		0.000442
SEPTEMBER		—		—		—		—		—		—		—		—		0.000051		0.000313		0.000364		0.000406
OCTOBER		—		—		—		—		—		—		—		—		—		0.000262		0.000313		0.000355
NOVEMBER		—		—		—		—		—		—		—		—		—		—		0.000051		0.000093
DECEMBER		—		—		—		—		—		—		—		—		—		—		—		0.000042

Table IV: 2013 Trust Administrative Expense (Cumulative $ per Unit)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
JANUARY		0.013781		0.026129		0.035393		0.047769		0.069997		0.089231		0.097282		0.106452		0.116225		0.126034		0.135838		0.145937
FEBRUARY		—		0.012348		0.021612		0.033988		0.056216		0.075450		0.083501		0.092671		0.102444		0.112253		0.122057		0.132156
MARCH		—		—		0.009264		0.021640		0.043868		0.063102		0.071153		0.080323		0.090096		0.099905		0.109709		0.119808
APRIL		—		—		—		0.012376		0.034604		0.053838		0.061889		0.071059		0.080832		0.090641		0.100445		0.110544
MAY		—		—		—		—		0.022228		0.041462		0.049513		0.058683		0.068456		0.078265		0.088069		0.098168
JUNE		—		—		—		—		—		0.019234		0.027285		0.036455		0.046228		0.056037		0.065841		0.075940
JULY		—		—		—		—		—		—		0.008051		0.017221		0.026994		0.036803		0.046607		0.056706
AUGUST		—		—		—		—		—		—		—		0.009170		0.018943		0.028752		0.038556		0.048655
SEPTEMBER		—		—		—		—		—		—		—		—		0.009773		0.019582		0.029386		0.039485
OCTOBER		—		—		—		—		—		—		—		—		—		0.009809		0.019613		0.029712
NOVEMBER		—		—		—		—		—		—		—		—		—		—		0.009804		0.019903
DECEMBER		—		—		—		—		—		—		—		—		—		—		—		0.010099

(SRT 2013 TAX)

7

SABINE ROYALTY TRUST TEXAS

TABLE A TEXAS: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.195317		0.481892		0.682142		1.068388		1.386253		1.587713		1.806165		2.172894		2.410871		2.710238		2.986339		3.132327
February		—		0.286575		0.486825		0.873071		1.190936		1.392396		1.610848		1.977577		2.215554		2.514921		2.791022		2.937010
March		—		—		0.200250		0.586496		0.904361		1.105821		1.324273		1.691002		1.928979		2.228346		2.504447		2.650435
April		—		—		—		0.386246		0.704111		0.905571		1.124023		1.490752		1.728729		2.028096		2.304197		2.450185
May		—		—		—		—		0.317865		0.519325		0.737777		1.104506		1.342483		1.641850		1.917951		2.063939
June		—		—		—		—		—		0.201460		0.419912		0.786641		1.024618		1.323985		1.600086		1.746074
July		—		—		—		—		—		—		0.218452		0.585181		0.823158		1.122525		1.398626		1.544614
August		—		—		—		—		—		—		—		0.366729		0.604706		0.904073		1.180174		1.326162
September		—		—		—		—		—		—		—		—		0.237977		0.537344		0.813445		0.959433
October		—		—		—		—		—		—		—		—		—		0.299367		0.575468		0.721456
November		—		—		—		—		—		—		—		—		—		—		0.276101		0.422089
December		—		—		—		—		—		—		—		—		—		—		—		0.145988

TABLE B TEXAS: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.012998		0.036365		0.049490		0.074182		0.097729		0.115775		0.130174		0.149454		0.161195		0.179910		0.194284		0.199538
February		—		0.023367		0.036492		0.061184		0.084731		0.102777		0.117176		0.136456		0.148197		0.166912		0.181286		0.186540
March		—		—		0.013125		0.037817		0.061364		0.079410		0.093809		0.113089		0.124830		0.143545		0.157919		0.163173
April		—		—		—		0.024692		0.048239		0.066285		0.080684		0.099964		0.111705		0.130420		0.144794		0.150048
May		—		—		—		—		0.023547		0.041593		0.055992		0.075272		0.087013		0.105728		0.120102		0.125356
June		—		—		—		—		—		0.018046		0.032445		0.051725		0.063466		0.082181		0.096555		0.101809
July		—		—		—		—		—		—		0.014399		0.033679		0.045420		0.064135		0.078509		0.083763
August		—		—		—		—		—		—		—		0.019280		0.031021		0.049736		0.064110		0.069364
September		—		—		—		—		—		—		—		—		0.011741		0.030456		0.044830		0.050084
October		—		—		—		—		—		—		—		—		—		0.018715		0.033089		0.038343
November		—		—		—		—		—		—		—		—		—		—		0.014374		0.019628
December		—		—		—		—		—		—		—		—		—		—		—		0.005254

TABLE C TEXAS: Interest Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000038		0.000083		0.000111		0.000162		0.000207		0.000248		0.000285		0.000321		0.000372		0.000634		0.000685		0.000727
February		—		0.000045		0.000073		0.000124		0.000169		0.000210		0.000247		0.000283		0.000334		0.000596		0.000647		0.000689
March		—		—		0.000028		0.000079		0.000124		0.000165		0.000202		0.000238		0.000289		0.000551		0.000602		0.000644
April		—		—		—		0.000051		0.000096		0.000137		0.000174		0.000210		0.000261		0.000523		0.000574		0.000616
May		—		—		—		—		0.000045		0.000086		0.000123		0.000159		0.000210		0.000472		0.000523		0.000565
June		—		—		—		—		—		0.000041		0.000078		0.000114		0.000165		0.000427		0.000478		0.000520
July		—		—		—		—		—		—		0.000037		0.000073		0.000124		0.000386		0.000437		0.000479
August		—		—		—		—		—		—		—		0.000036		0.000087		0.000349		0.000400		0.000442
September		—		—		—		—		—		—		—		—		0.000051		0.000313		0.000364		0.000406
October		—		—		—		—		—		—		—		—		—		0.000262		0.000313		0.000355
November		—		—		—		—		—		—		—		—		—		—		0.000051		0.000093
December		—		—		—		—		—		—		—		—		—		—		—		0.000042

TABLE D TEXAS: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.009343		0.018640		0.025133		0.034909		0.052238		0.065532		0.070749		0.077584		0.084369		0.091348		0.098171		0.104219
February		—		0.009297		0.015790		0.025566		0.042895		0.056189		0.061406		0.068241		0.075026		0.082005		0.088828		0.094876
March		—		—		0.006493		0.016269		0.033598		0.046892		0.052109		0.058944		0.065729		0.072708		0.079531		0.085579
April		—		—		—		0.009776		0.027105		0.040399		0.045616		0.052451		0.059236		0.066215		0.073038		0.079086
May		—		—		—		—		0.017329		0.030623		0.035840		0.042675		0.049460		0.056439		0.063262		0.069310
June		—		—		—		—		—		0.013294		0.018511		0.025346		0.032131		0.039110		0.045933		0.051981
July		—		—		—		—		—		—		0.005217		0.012052		0.018837		0.025816		0.032639		0.038687
August		—		—		—		—		—		—		—		0.006835		0.013620		0.020599		0.027422		0.033470
September		—		—		—		—		—		—		—		—		0.006785		0.013764		0.020587		0.026635
October		—		—		—		—		—		—		—		—		—		0.006979		0.013802		0.019850
November		—		—		—		—		—		—		—		—		—		—		0.006823		0.012871
December		—		—		—		—		—		—		—		—		—		—		—		0.006048

(SRT 2013 TAX)

8

SABINE ROYALTY TRUST OKLAHOMA

TABLE A OKLAHOMA: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.045627		0.090833		0.138688		0.185919		0.230556		0.277158		0.346090		0.411232		0.471545		0.534708		0.598137		0.647335
February		—		0.045206		0.093061		0.140292		0.184929		0.231531		0.300463		0.365605		0.425918		0.489081		0.552510		0.601708
March		—		—		0.047855		0.095086		0.139723		0.186325		0.255257		0.320399		0.380712		0.443875		0.507304		0.556502
April		—		—		—		0.047231		0.091868		0.138470		0.207402		0.272544		0.332857		0.396020		0.459449		0.508647
May		—		—		—		—		0.044637		0.091239		0.160171		0.225313		0.285626		0.348789		0.412218		0.461416
June		—		—		—		—		—		0.046602		0.115534		0.180676		0.240989		0.304152		0.367581		0.416779
July		—		—		—		—		—		—		0.068932		0.134074		0.194387		0.257550		0.320979		0.370177
August		—		—		—		—		—		—		—		0.065142		0.125455		0.188618		0.252047		0.301245
September		—		—		—		—		—		—		—		—		0.060313		0.123476		0.186905		0.236103
October		—		—		—		—		—		—		—		—		—		0.063163		0.126592		0.175790
November		—		—		—		—		—		—		—		—		—		—		0.063429		0.112627
December		—		—		—		—		—		—		—		—		—		—		—		0.049198

TABLE B OKLAHOMA: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.005265		0.010485		0.015724		0.021050		0.026002		0.031289		0.035776		0.042945		0.048515		0.054564		0.057091		0.062583
February		—		0.005220		0.010459		0.015785		0.020737		0.026024		0.030511		0.037680		0.043250		0.049299		0.051826		0.057318
March		—		—		0.005239		0.010565		0.015517		0.020804		0.025291		0.032460		0.038030		0.044079		0.046606		0.052098
April		—		—		—		0.005326		0.010278		0.015565		0.020052		0.027221		0.032791		0.038840		0.041367		0.046859
May		—		—		—		—		0.004952		0.010239		0.014726		0.021895		0.027465		0.033514		0.036041		0.041533
June		—		—		—		—		—		0.005287		0.009774		0.016943		0.022513		0.028562		0.031089		0.036581
July		—		—		—		—		—		—		0.004487		0.011656		0.017226		0.023275		0.025802		0.031294
August		—		—		—		—		—		—		—		0.007169		0.012739		0.018788		0.021315		0.026807
September		—		—		—		—		—		—		—		—		0.005570		0.011619		0.014146		0.019638
October		—		—		—		—		—		—		—		—		—		0.006049		0.008576		0.014068
November		—		—		—		—		—		—		—		—		—		—		0.002527		0.008019
December		—		—		—		—		—		—		—		—		—		—		—		0.005492

TABLE C OKLAHOMA: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.002184		0.003651		0.005202		0.006398		0.008833		0.011909		0.013556		0.014771		0.016491		0.017964		0.019533		0.021573
February		—		0.001467		0.003018		0.004214		0.006649		0.009725		0.011372		0.012587		0.014307		0.015780		0.017349		0.019389
March		—		—		0.001551		0.002747		0.005182		0.008258		0.009905		0.011120		0.012840		0.014313		0.015882		0.017922
April		—		—		—		0.001196		0.003631		0.006707		0.008354		0.009569		0.011289		0.012762		0.014331		0.016371
May		—		—		—		—		0.002435		0.005511		0.007158		0.008373		0.010093		0.011566		0.013135		0.015175
June		—		—		—		—		—		0.003076		0.004723		0.005938		0.007658		0.009131		0.010700		0.012740
July		—		—		—		—		—		—		0.001647		0.002862		0.004582		0.006055		0.007624		0.009664
August		—		—		—		—		—		—		—		0.001215		0.002935		0.004408		0.005977		0.008017
September		—		—		—		—		—		—		—		—		0.001720		0.003193		0.004762		0.006802
October		—		—		—		—		—		—		—		—		—		0.001473		0.003042		0.005082
November		—		—		—		—		—		—		—		—		—		—		0.001569		0.003609
December		—		—		—		—		—		—		—		—		—		—		—		0.002040

(SRT 2013 TAX)

9

SABINE ROYALTY TRUST FLORIDA

TABLE A FLORIDA: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.009285		0.009436		0.014147		0.019255		0.023701		0.028782		0.031188		0.035789		0.040342		0.045124		0.050710		0.056487
February		—		0.000151		0.004862		0.009970		0.014416		0.019497		0.021903		0.026504		0.031057		0.035839		0.041425		0.047202
March		—		—		0.004711		0.009819		0.014265		0.019346		0.021752		0.026353		0.030906		0.035688		0.041274		0.047051
April		—		—		—		0.005108		0.009554		0.014635		0.017041		0.021642		0.026195		0.030977		0.036563		0.042340
May		—		—		—		—		0.004446		0.009527		0.011933		0.016534		0.021087		0.025869		0.031455		0.037232
June		—		—		—		—		—		0.005081		0.007487		0.012088		0.016641		0.021423		0.027009		0.032786
July		—		—		—		—		—		—		0.002406		0.007007		0.011560		0.016342		0.021928		0.027705
August		—		—		—		—		—		—		—		0.004601		0.009154		0.013936		0.019522		0.025299
September		—		—		—		—		—		—		—		—		0.004553		0.009335		0.014921		0.020698
October		—		—		—		—		—		—		—		—		—		0.004782		0.010368		0.016145
November		—		—		—		—		—		—		—		—		—		—		0.005586		0.011363
December		—		—		—		—		—		—		—		—		—		—		—		0.005777

TABLE B FLORIDA: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000405		0.000413		0.000624		0.000861		0.001060		0.001294		0.001404		0.001616		0.001822		0.002052		0.002316		0.002584
February		—		0.000008		0.000219		0.000456		0.000655		0.000889		0.000999		0.001211		0.001417		0.001647		0.001911		0.002179
March		—		—		0.000211		0.000448		0.000647		0.000881		0.000991		0.001203		0.001409		0.001639		0.001903		0.002171
April		—		—		—		0.000237		0.000436		0.000670		0.000780		0.000992		0.001198		0.001428		0.001692		0.001960
May		—		—		—		—		0.000199		0.000433		0.000543		0.000755		0.000961		0.001191		0.001455		0.001723
June		—		—		—		—		—		0.000234		0.000344		0.000556		0.000762		0.000992		0.001256		0.001524
July		—		—		—		—		—		—		0.000110		0.000322		0.000528		0.000758		0.001022		0.001290
August		—		—		—		—		—		—		—		0.000212		0.000418		0.000648		0.000912		0.001180
September		—		—		—		—		—		—		—		—		0.000206		0.000436		0.000700		0.000968
October		—		—		—		—		—		—		—		—		—		0.000230		0.000494		0.000762
November		—		—		—		—		—		—		—		—		—		—		0.000264		0.000532
December		—		—		—		—		—		—		—		—		—		—		—		0.000268

TABLE C FLORIDA: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000445		0.000450		0.000603		0.000732		0.000975		0.001310		0.001367		0.001453		0.001583		0.001695		0.001833		0.002073
February		—		0.000005		0.000158		0.000287		0.000530		0.000865		0.000922		0.001008		0.001138		0.001250		0.001388		0.001628
March		—		—		0.000153		0.000282		0.000525		0.000860		0.000917		0.001003		0.001133		0.001245		0.001383		0.001623
April		—		—		—		0.000129		0.000372		0.000707		0.000764		0.000850		0.000980		0.001092		0.001230		0.001470
May		—		—		—		—		0.000243		0.000578		0.000635		0.000721		0.000851		0.000963		0.001101		0.001341
June		—		—		—		—		—		0.000335		0.000392		0.000478		0.000608		0.000720		0.000858		0.001098
July		—		—		—		—		—		—		0.000057		0.000143		0.000273		0.000385		0.000523		0.000763
August		—		—		—		—		—		—		—		0.000086		0.000216		0.000328		0.000466		0.000706
September		—		—		—		—		—		—		—		—		0.000130		0.000242		0.000380		0.000620
October		—		—		—		—		—		—		—		—		—		0.000112		0.000250		0.000490
November		—		—		—		—		—		—		—		—		—		—		0.000138		0.000378
December		—		—		—		—		—		—		—		—		—		—		—		0.000240

(SRT 2013 TAX)

10

SABINE ROYALTY TRUST LOUISIANA

TABLE A LOUISIANA: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.006922		0.016429		0.020820		0.032464		0.039686		0.044680		0.052195		0.062905		0.066011		0.078375		0.085955		0.094518
February		—		0.009507		0.013898		0.025542		0.032764		0.037758		0.045273		0.055983		0.059089		0.071453		0.079033		0.087596
March		—		—		0.004391		0.016035		0.023257		0.028251		0.035766		0.046476		0.049582		0.061946		0.069526		0.078089
April		—		—		—		0.011644		0.018866		0.023860		0.031375		0.042085		0.045191		0.057555		0.065135		0.073698
May		—		—		—		—		0.007222		0.012216		0.019731		0.030441		0.033547		0.045911		0.053491		0.062054
June		—		—		—		—		—		0.004994		0.012509		0.023219		0.026325		0.038689		0.046269		0.054832
July		—		—		—		—		—		—		0.007515		0.018225		0.021331		0.033695		0.041275		0.049838
August		—		—		—		—		—		—		—		0.010710		0.013816		0.026180		0.033760		0.042323
September		—		—		—		—		—		—		—		—		0.003106		0.015470		0.023050		0.031613
October		—		—		—		—		—		—		—		—		—		0.012364		0.019944		0.028507
November		—		—		—		—		—		—		—		—		—		—		0.007580		0.016143
December		—		—		—		—		—		—		—		—		—		—		—		0.008563

TABLE B LOUISIANA: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000605		0.001417		0.001693		0.002777		0.003327		0.003698		0.004354		0.005235		0.005519		0.006619		0.009017		0.009844
February		—		0.000812		0.001088		0.002172		0.002722		0.003093		0.003749		0.004630		0.004914		0.006014		0.008412		0.009239
March		—		—		0.000276		0.001360		0.001910		0.002281		0.002937		0.003818		0.004102		0.005202		0.007600		0.008427
April		—		—		—		0.001084		0.001634		0.002005		0.002661		0.003542		0.003826		0.004926		0.007324		0.008151
May		—		—		—		—		0.000550		0.000921		0.001577		0.002458		0.002742		0.003842		0.006240		0.007067
June		—		—		—		—		—		0.000371		0.001027		0.001908		0.002192		0.003292		0.005690		0.006517
July		—		—		—		—		—		—		0.000656		0.001537		0.001821		0.002921		0.005319		0.006146
August		—		—		—		—		—		—		—		0.000881		0.001165		0.002265		0.004663		0.005490
September		—		—		—		—		—		—		—		—		0.000284		0.001384		0.003782		0.004609
October		—		—		—		—		—		—		—		—		—		0.001100		0.003498		0.004325
November		—		—		—		—		—		—		—		—		—		—		0.002398		0.003225
December		—		—		—		—		—		—		—		—		—		—		—		0.000827

TABLE C LOUISIANA: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000331		0.000639		0.000781		0.001076		0.001470		0.001800		0.001980		0.002180		0.002269		0.002557		0.002745		0.003100
February		—		0.000308		0.000450		0.000745		0.001139		0.001469		0.001649		0.001849		0.001938		0.002226		0.002414		0.002769
March		—		—		0.000142		0.000437		0.000831		0.001161		0.001341		0.001541		0.001630		0.001918		0.002106		0.002461
April		—		—		—		0.000295		0.000689		0.001019		0.001199		0.001399		0.001488		0.001776		0.001964		0.002319
May		—		—		—		—		0.000394		0.000724		0.000904		0.001104		0.001193		0.001481		0.001669		0.002024
June		—		—		—		—		—		0.000330		0.000510		0.000710		0.000799		0.001087		0.001275		0.001630
July		—		—		—		—		—		—		0.000180		0.000380		0.000469		0.000757		0.000945		0.001300
August		—		—		—		—		—		—		—		0.000200		0.000289		0.000577		0.000765		0.001120
September		—		—		—		—		—		—		—		—		0.000089		0.000377		0.000565		0.000920
October		—		—		—		—		—		—		—		—		—		0.000288		0.000476		0.000831
November		—		—		—		—		—		—		—		—		—		—		0.000188		0.000543
December		—		—		—		—		—		—		—		—		—		—		—		0.000355

(SRT 2013 TAX)

11

SABINE ROYALTY TRUST MISSISSIPPI

TABLE A MISSISSIPPI: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.007699		0.022385		0.033516		0.046479		0.058006		0.068927		0.080843		0.093139		0.104349		0.117279		0.129720		0.139124
February		—		0.014686		0.025817		0.038780		0.050307		0.061228		0.073144		0.085440		0.096650		0.109580		0.122021		0.131425
March		—		—		0.011131		0.024094		0.035621		0.046542		0.058458		0.070754		0.081964		0.094894		0.107335		0.116739
April		—		—		—		0.012963		0.024490		0.035411		0.047327		0.059623		0.070833		0.083763		0.096204		0.105608
May		—		—		—		—		0.011527		0.022448		0.034364		0.046660		0.057870		0.070800		0.083241		0.092645
June		—		—		—		—		—		0.010921		0.022837		0.035133		0.046343		0.059273		0.071714		0.081118
July		—		—		—		—		—		—		0.011916		0.024212		0.035422		0.048352		0.060793		0.070197
August		—		—		—		—		—		—		—		0.012296		0.023506		0.036436		0.048877		0.058281
September		—		—		—		—		—		—		—		—		0.011210		0.024140		0.036581		0.045985
October		—		—		—		—		—		—		—		—		—		0.012930		0.025371		0.034775
November		—		—		—		—		—		—		—		—		—		—		0.012441		0.021845
December		—		—		—		—		—		—		—		—		—		—		—		0.009404

TABLE B MISSISSIPPI: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000364		0.001408		0.002011		0.002768		0.003546		0.004095		0.004773		0.005582		0.006197		0.006935		0.007607		0.008114
February		—		0.001044		0.001647		0.002404		0.003182		0.003731		0.004409		0.005218		0.005833		0.006571		0.007243		0.007750
March		—		—		0.000603		0.001360		0.002138		0.002687		0.003365		0.004174		0.004789		0.005527		0.006199		0.006706
April		—		—		—		0.000757		0.001535		0.002084		0.002762		0.003571		0.004186		0.004924		0.005596		0.006103
May		—		—		—		—		0.000778		0.001327		0.002005		0.002814		0.003429		0.004167		0.004839		0.005346
June		—		—		—		—		—		0.000549		0.001227		0.002036		0.002651		0.003389		0.004061		0.004568
July		—		—		—		—		—		—		0.000678		0.001487		0.002102		0.002840		0.003512		0.004019
August		—		—		—		—		—		—		—		0.000809		0.001424		0.002162		0.002834		0.003341
September		—		—		—		—		—		—		—		—		0.000615		0.001353		0.002025		0.002532
October		—		—		—		—		—		—		—		—		—		0.000738		0.001410		0.001917
November		—		—		—		—		—		—		—		—		—		—		0.000672		0.001179
December		—		—		—		—		—		—		—		—		—		—		—		0.000507

TABLE C MISSISSIPPI: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.000369		0.000846		0.001207		0.001535		0.002164		0.002885		0.003170		0.003399		0.003719		0.004021		0.004329		0.004719
February		—		0.000477		0.000838		0.001166		0.001795		0.002516		0.002801		0.003030		0.003350		0.003652		0.003960		0.004350
March		—		—		0.000361		0.000689		0.001318		0.002039		0.002324		0.002553		0.002873		0.003175		0.003483		0.003873
April		—		—		—		0.000328		0.000957		0.001678		0.001963		0.002192		0.002512		0.002814		0.003122		0.003512
May		—		—		—		—		0.000629		0.001350		0.001635		0.001864		0.002184		0.002486		0.002794		0.003184
June		—		—		—		—		—		0.000721		0.001006		0.001235		0.001555		0.001857		0.002165		0.002555
July		—		—		—		—		—		—		0.000285		0.000514		0.000834		0.001136		0.001444		0.001834
August		—		—		—		—		—		—		—		0.000229		0.000549		0.000851		0.001159		0.001549
September		—		—		—		—		—		—		—		—		0.000320		0.000622		0.000930		0.001320
October		—		—		—		—		—		—		—		—		—		0.000302		0.000610		0.001000
November		—		—		—		—		—		—		—		—		—		—		0.000308		0.000698
December		—		—		—		—		—		—		—		—		—		—		—		0.000390

(SRT 2013 TAX)

12

SABINE ROYALTY TRUST NEW MEXICO

TABLE A NEW MEXICO: Gross Royalty Income

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.023170		0.047625		0.065037		0.090766		0.112736		0.135129		0.162962		0.195389		0.220967		0.249031		0.280472		0.305221
February		—		0.024455		0.041867		0.067596		0.089566		0.111959		0.139792		0.172219		0.197797		0.225861		0.257302		0.282051
March		—		—		0.017412		0.043141		0.065111		0.087504		0.115337		0.147764		0.173342		0.201406		0.232847		0.257596
April		—		—		—		0.025729		0.047699		0.070092		0.097925		0.130352		0.155930		0.183994		0.215435		0.240184
May		—		—		—		—		0.021970		0.044363		0.072196		0.104623		0.130201		0.158265		0.189706		0.214455
June		—		—		—		—		—		0.022393		0.050226		0.082653		0.108231		0.136295		0.167736		0.192485
July		—		—		—		—		—		—		0.027833		0.060260		0.085838		0.113902		0.145343		0.170092
August		—		—		—		—		—		—		—		0.032427		0.058005		0.086069		0.117510		0.142259
September		—		—		—		—		—		—		—		—		0.025578		0.053642		0.085083		0.109832
October		—		—		—		—		—		—		—		—		—		0.028064		0.059505		0.084254
November		—		—		—		—		—		—		—		—		—		—		0.031441		0.056190
December		—		—		—		—		—		—		—		—		—		—		—		0.024749

TABLE B NEW MEXICO: Severance Tax

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October			November			December
January		0.003481		0.006887		0.009537		0.013450		0.016901		0.020387		0.024307		0.029030		0.032899		0.023177			0.026682			0.030639
February		—		0.003406		0.006056		0.009969		0.013420		0.016906		0.020826		0.025549		0.029418		0.019696			0.023201			0.027158
March		—		—		0.002650		0.006563		0.010014		0.013500		0.017420		0.022143		0.026012		0.016290			0.019795			0.023752
April		—		—		—		0.003913		0.007364		0.010850		0.014770		0.019493		0.023362		0.013640			0.017145			0.021102
May		—		—		—		—		0.003451		0.006937		0.010857		0.015580		0.019449		0.009727			0.013232			0.017189
June		—		—		—		—		—		0.003486		0.007406		0.012129		0.015998		0.006276			0.009781			0.013738
July		—		—		—		—		—		—		0.003920		0.008643		0.012512		0.002790			0.006295			0.010252
August		—		—		—		—		—		—		—		0.004723		0.008592		(0.001130	)		0.002375			0.006332
September		—		—		—		—		—		—		—		—		0.003869		(0.005853	)		(0.002348	)		0.001609
October		—		—		—		—		—		—		—		—		—		(0.009722	)		(0.006217	)		(0.002260	)
November		—		—		—		—		—		—		—		—		—		—			0.003505			0.007462
December		—		—		—		—		—		—		—		—		—		—			—			0.003957

TABLE C NEW MEXICO: Administrative Expense

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
January		0.001109		0.001903		0.002467		0.003119		0.004317		0.005795		0.006460		0.007065		0.007794		0.008449		0.009227		0.010253
February		—		0.000794		0.001358		0.002010		0.003208		0.004686		0.005351		0.005956		0.006685		0.007340		0.008118		0.009144
March		—		—		0.000564		0.001216		0.002414		0.003892		0.004557		0.005162		0.005891		0.006546		0.007324		0.008350
April		—		—		—		0.000652		0.001850		0.003328		0.003993		0.004598		0.005327		0.005982		0.006760		0.007786
May		—		—		—		—		0.001198		0.002676		0.003341		0.003946		0.004675		0.005330		0.006108		0.007134
June		—		—		—		—		—		0.001478		0.002143		0.002748		0.003477		0.004132		0.004910		0.005936
July		—		—		—		—		—		—		0.000665		0.001270		0.001999		0.002654		0.003432		0.004458
August		—		—		—		—		—		—		—		0.000605		0.001334		0.001989		0.002767		0.003793
September		—		—		—		—		—		—		—		—		0.000729		0.001384		0.002162		0.003188
October		—		—		—		—		—		—		—		—		—		0.000655		0.001433		0.002459
November		—		—		—		—		—		—		—		—		—		—		0.000778		0.001804
December		—		—		—		—		—		—		—		—		—		—		—		0.001026

(SRT 2013 TAX)

13

SABINE ROYALTY TRUST

Depletion Schedule D-I

The cumulative and noncumulative cost depletion factors reflected in Depletion Schedule D-I should be used to compute 2013 federal cost depletion amounts attributable to Units purchased for which the Unit holder initially became entitled to distributions in 2013. This schedule should not be used to compute depletion for any other Units owned. (See accompanying information for computation instructions.)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	January		February		March		April		May		June		July		August		September		October		November		December
January		0.008325		0.020261		0.028522		0.044787		0.057155		0.065756		0.073860		0.086290		0.094339		0.104467		0.114589		0.124933
February				0.011936		0.020197		0.036462		0.048830		0.057431		0.065535		0.077965		0.086014		0.096142		0.106264		0.116608
March						0.008261		0.024526		0.036894		0.045495		0.053599		0.066029		0.074078		0.084206		0.094328		0.104672
April								0.016265		0.028633		0.037234		0.045338		0.057768		0.065817		0.075945		0.086067		0.096411
May										0.012368		0.020969		0.029073		0.041503		0.049552		0.059680		0.069802		0.080146
June												0.008601		0.016705		0.029135		0.037184		0.047312		0.057434		0.067778
July														0.008104		0.020534		0.028583		0.038711		0.048833		0.059177
August																0.012430		0.020479		0.030607		0.040729		0.051073
September																		0.008049		0.018177		0.028299		0.038643
October																				0.010128		0.020250		0.030594
November																						0.010122		0.020466
December																								0.010344

Depletion Schedule D-II

The non-cumulative cost depletion factors reflected in Depletion Schedule D-II should be used to compute 2013 state cost depletion amounts attributable to Units purchased for which the Unit holder initially became entitled to distributions in any year. The applicable number to use is the number related to the last month in which the units were owned in 2013. (See accompanying information for computation instructions.)

STATE DEPLETION FACTORS	January		February		March		April		May		June		July		August		September		October		November		December
Florida		0.000434		0.000006		0.000186		0.000222		0.000206		0.000223		0.000105		0.000230		0.000219		0.000223		0.000234		0.000262
Louisiana		0.000168		0.000257		0.000094		0.000251		0.000192		0.000107		0.000164		0.000285		0.000000		0.000444		0.000280		0.000200
Mississippi		0.000199		0.000433		0.000257		0.000339		0.000297		0.000251		0.000319		0.000310		0.000280		0.000325		0.000303		0.000256
New Mexico		0.000588		0.000659		0.000457		0.000692		0.000590		0.000562		0.000630		0.000793		0.000621		0.000689		0.000743		0.000600
Oklahoma		0.001264		0.001182		0.001238		0.001187		0.001108		0.001152		0.001229		0.001350		0.001375		0.001454		0.001443		0.001072
Texas		0.005672		0.009399		0.006029		0.013574		0.009975		0.006306		0.005657		0.009462		0.005554		0.006993		0.007119		0.007954
TOTAL		0.008325		0.011936		0.008261		0.016265		0.012368		0.008601		0.008104		0.012430		0.008049		0.010128		0.010122		0.010344

(SRT 2013 TAX)

14

SABINE ROYALTY TRUST

Depletion Schedule D-III

The cumulative federal cost depletion factors reflected in Depletion Schedule D-III should be used to compute 2013 federal cost depletion amounts attributable to Units purchased for which the Unit holder initially became entitled to distributions in the year stated. For depletion factors relating to the individual states, please use Depletion Schedule D-II on page 14. (See accompanying information for computation instructions.)

For a Unit acquired of record during the year of:	LAST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013
	2013
	January		February		March		April		May		June		July		August		September		October		November		December
Original Distribution		.008279		.020969		.029648		.046735		.059690		.068599		.077044		.089842		.098251		.108497		.118822		.129465
1983		.007485		.019195		.027037		.043454		.055713		.063836		.071310		.083213		.090653		.099825		.109131		.119077
1984		.004686		.012052		.016971		.027326		.035047		.040142		.044819		.052298		.056948		.062695		.068523		.074777
1985		.006312		.016252		.022875		.036837		.047247		.054115		.060425		.070511		.076782		.084524		.092382		.100815
Before March 17, 1986		.004982		.012837		.018063		.029117		.037353		.042776		.047750		.055723		.060665		.066769		.072969		.079638
After March 17, 1986		.003825		.009854		.013864		.022338		.028655		.032818		.036641		.042761		.046558		.051248		.056011		.061128
1987		.005310		.013621		.019168		.030874		.039600		.045358		.050636		.059092		.064347		.070831		.077416		.084490
1988		.005780		.014737		.020760		.033342		.042743		.048987		.054722		.063858		.069583		.076625		.083775		.091416
1989		.005610		.014155		.019970		.031917		.040878		.046891		.052432		.061177		.066735		.073535		.080437		.087749
1990		.005349		.013419		.018931		.030222		.038698		.044405		.049661		.057951		.063233		.069691		.076245		.083179
1991		.005067		.012546		.017702		.028083		.035914		.041268		.046235		.053977		.058983		.065068		.071254		.077711
1992		.005976		.014727		.020834		.032827		.041922		.048230		.054144		.063199		.069173		.076380		.083700		.091228
1993		.006261		.015155		.021429		.033688		.043004		.049508		.055570		.064875		.071041		.078471		.086020		.093777
1994		.005643		.013396		.018964		.029729		.037932		.043698		.049031		.057227		.062702		.069287		.075970		.082835
1995		.006371		.014599		.020685		.032230		.041078		.047396		.053175		.062057		.068091		.075287		.082596		.090089
1996		.006156		.013988		.019882		.030710		.039069		.045152		.050780		.059257		.065153		.072132		.079211		.086334
1997		.008501		.019507		.027656		.043030		.054824		.063269		.071022		.082886		.090969		.100617		.110406		.120396
1998		.009010		.020908		.029650		.046119		.058754		.067788		.076144		.088849		.097511		.107861		.118347		.129020
1999		.008939		.021219		.030029		.046824		.059676		.068790		.081496		.094420		.103109		.113648		.124279		.135084
2000		.008845		.020980		.029683		.046127		.058749		.067761		.076243		.088983		.097624		.108056		.118582		.129227
2001		.008961		.020618		.029265		.044453		.056345		.065263		.073895		.086292		.095091		.105718		.116356		.126622
2002		.009375		.021166		.029966		.046002		.058448		.067617		.076212		.089008		.097904		.108604		.119396		.130121
2003		.009082		.020848		.029604		.045652		.058071		.067141		.075701		.088395		.097201		.107757		.118410		.129013
2004		.008956		.020869		.029505		.045761		.058261		.067244		.075655		.088333		.096943		.107361		.117876		.128490
2005		.009182		.021084		.029866		.046088		.058621		.067735		.076259		.089020		.097822		.108389		.119057		.129755
2006		.008900		.020763		.029366		.045476		.057879		.066819		.075226		.087847		.096439		.106847		.117341		.127881
2007		.008702		.020311		.028680		.044705		.056950		.065687		.073822		.086214		.094538		.104642		.114855		.125232
2008		.008342		.019731		.027853		.043499		.055459		.063921		.071817		.083870		.091900		.101694		.111579		.121660
2009		.008150		.019577		.027666		.043117		.054942		.063317		.071234		.083170		.091146		.100930		.110760		.120697
2010		.008233		.020027		.028238		.044242		.056431		.064950		.072997		.085258		.093277		.103291		.113310		.123508
2011		.008079		.019814		.027907		.043792		.055877		.064294		.072267		.084423		.092333		.102222		.112127		.122219
2012		0.008260		.020206		0.028470		.044784		.057169		.065757		.073834		.086247		.094289		.104316		.114384		.124713

(SRT 2013 TAX)

15

SABINE ROYALTY TRUST

Depletion Schedule D-IV

The noncumulative and cumulative depletion factors reflected in Depletion Schedule D-IV should be used to compute 2013 Federal percentage depletion amounts attributable to Units purchased for which the Unit holder initially became entitled to distributions in any year. (See accompanying information for computation instructions.)

FIRST MONTH IN WHICH UNITS WERE OWNED ON THE MONTHLY RECORD DATE IN 2013	January		February		March		April		May		June		July		August		September		October		November		December
JANUARY		0.043203		0.100290		0.143153		0.216491		0.277641		0.321359		0.371917		0.445703		0.497114		0.560215		0.619702		0.656254
FEBRUARY		—		0.057087		0.099950		0.173288		0.234438		0.278156		0.328714		0.402500		0.453911		0.517012		0.576499		0.613051
MARCH		—		—		0.042863		0.116201		0.177351		0.221069		0.271627		0.345413		0.396824		0.459925		0.519412		0.555964
APRIL		—		—		—		0.073338		0.134488		0.178206		0.228764		0.302550		0.353961		0.417062		0.476549		0.513101
MAY		—		—		—		—		0.061150		0.104868		0.155426		0.229212		0.280623		0.343724		0.403211		0.439763
JUNE		—		—		—		—		—		0.043718		0.094276		0.168062		0.219473		0.282574		0.342061		0.378613
JULY		—		—		—		—		—		—		0.050558		0.124344		0.175755		0.238856		0.298343		0.334895
AUGUST		—		—		—		—		—		—		—		0.073786		0.125197		0.188298		0.247785		0.284337
SEPTEMBER		—		—		—		—		—		—		—		—		0.051411		0.114512		0.173999		0.210551
OCTOBER		—		—		—		—		—		—		—		—		—		0.063101		0.122588		0.159140
NOVEMBER		—		—		—		—		—		—		—		—		—		—		0.059487		0.096039
DECEMBER		—		—		—		—		—		—		—		—		—		—		—		0.036552

(SRT 2013 TAX)

16

17

18

19

20

SABINE ROYALTY TRUST

TAX COMPUTATION WORKSHEET

2013

(RETAIN THIS WORKPAPER AS PART OF YOUR PERMANENT TAX RECORDS)

Part I

INCOME AND EXPENSE

	A		B		C
Item	Number of Units Owned (Note 1)		Income/Expense Per Unit from Appropriate Schedule(s) (Note 2)		Totals	Where to Reflect on 2013 Form 1040 (Note 3)
Gross Royalty Income		X		=		Line 4, Part I, Schedule E
Severance Tax		X		=		Line 16, Part I, Schedule E
Interest Income		X		=		Line 1, Part I, Schedule B
Administrative Expense		X		=		Line 19, Part I, Schedule E

Part II

COST DEPLETION (Note 4)

Original Basis		Cost Depletion Allowable in Prior Calendar Years (Note 5)		Adjusted Basis for Cost Depletion Purposes		Appropriate 2013 Cost Depletion Factor (Note 4)		2013 Cost Depletion
	-		=		X		=

* Reflect cost depletion on 2013 Form 1040, line 18, Part 1, Schedule E (Note 3).

Part III

COMPUTATION OF GAIN OR (LOSS) FOR UNITS SOLD

Net Sales Price		Adjusted Basis (Note 6)		Gain (Loss)	Where to Reflect on 2013 Form 1040 (Note 3)
	-		=		Form 4797 Part III, Lines 19-24 and Schedule D

Notes

(1) In order to correctly calculate total income and expense to be reported on your 2013 federal and, if applicable, state tax returns, it is recommended that you reproduce and complete a separate Tax Computation Worksheet for each block of Units acquired and disposed of at different times, as different factors apply depending on when units were acquired or disposed of. If more than one Tax Computation Worksheet is required, the separate amounts from each Tax Computation Worksheet should be added together and those aggregate numbers reported on your 2013 income tax returns.

(2) If you did not become a Unit holder of record of any Unit(s) or did not cease to be a Unit holder of record of any Unit(s) during the period from January 15, 2013 through December 16, 2013, then the amounts reflected on the cumulative schedule for 2013 (located on page 5) should be used to complete Part I. See Comprehensive Example 1 on page 22. If any Units were held of record for only part of the period defined above, then the appropriate federal income and expense factors for Part I can be determined by using Tables I-IV (on pages 6 and 7) by locating the factor at the intersection of the first and last month in which the Units were owned by the Unit holder on the Monthly Record Date in 2013. See Comprehensive Examples 2 and 3 on pages 23 and 24 for further explanation. The appropriate state income and expense factors can be determined by using the state tables in the same manner, which are located on pages 8 through 13.

(3) The Trustee believes that individual Unit holders owning the Units as an investment should report the amounts determined in this manner. See Sample Tax Forms on pages 17-20. The U.S. Corporation Income Tax Return (Form 1120) does not require that royalty income and related expenses be separately identified on any specific schedules. See “Sale or Exchange of Units” on page A-4 for a discussion of the tax consequences resulting from the sale of a Unit.

(4) The appropriate depletion schedule(s) to be utilized depends on when the Units were acquired. See “Computing Depletion” on page 2 to determine the proper schedule(s) to be used. This worksheet assumes a Unit holder will take the cost depletion deduction. Some Unit holders may be entitled to a percentage depletion deduction in lieu of a cost depletion deduction, in which case Depletion Schedule D-IV (on page 16) should be used to compute such Unit holder’s depletion deduction for purposes of Part II of this worksheet. See pages 2 and A-2 - A-3 of this booklet for additional information regarding depletion deductions.

(5) Cost depletion allowable in prior calendar years cannot be computed from the schedules contained in this booklet. Depletion schedules contained in Sabine Royalty Trust Tax Information Booklet(s) from prior years should be used to determine the appropriate cost depletion amount(s) allowable in prior calendar years.

(6) The adjusted basis is equal to the cost or other basis of the Unit(s) less the cost depletion allowable from the date of acquisition through the date of sale (whether or not deducted).

(SRT 2013 TAX)

21

COMPREHENSIVE EXAMPLE 1

The following example illustrates the computations necessary for an individual to determine income and expense attributable to Units acquired in March of 1984 and held throughout 2013.

COMPUTATION OF INCOME AND EXPENSE FOR UNITS OWNED ON ALL MONTHLY RECORD DATES IN 2013

SABINE ROYALTY TRUST

TAX COMPUTATION WORKSHEET 2013

(RETAIN THIS WORKPAPER AS PART OF YOUR PERMANENT TAX RECORDS)

Part I

INCOME AND EXPENSE

	A			B			C
Item	Number of Units Owned (Note 1)			Income/Expense Per Unit from Appropriate Schedule(s) (Note 2)			Totals		Where to Reflect on 2013 Form 1040 (Note 3)
Gross Royalty Income		100	X	$	4.375012	=	$	437.50	Line 4, Part I, Schedule E
Severance Tax		100	X	$	.313302	=	$	31.33	Line 16, Part I, Schedule E
Interest Income		100	X	$	.000727	=	$	.07	Line 1, Part I, Schedule B
Administrative Expense		100	X	$	.145937	=	$	14.59	Line 19, Part I, Schedule E

Part II

COST DEPLETION (Note 4)

Assumed Original Basis*			Cost  Depletion Allowable in Prior Calendar Years (Notes 4 and 5)			Adjusted Basis for Cost Depletion Purposes			Appropriate 2013 Cost Depletion Factor per Depletion Schedule D-III			2013 Cost Depletion**
$	2,100.00	-	$	2,038.65	=	$	61.35	X		.074777	=	$	4.59

* This number is used for example purposes only. Each Unit holder’s basis is unique to that specific Unit holder.

** Reflect cost depletion on 2013 Form 1040, line 18, Part 1, Schedule E (Note 3).

See Page 21 for Applicable Notes.

(SRT 2013 TAX)

22

COMPREHENSIVE EXAMPLE 2

The following example illustrates the computations necessary for an individual to determine income and expenses and gain or loss on Units acquired in 1984 and disposed of during 2013. The factors in this example are located at the intersection of January and March on the appropriate tables (i.e., the first and last month of 2013 in which Units were owned on Monthly Record Dates).

Acquisition Date	Units Acquired	Original Basis	Sales Date	Units Sold	Sales Price
03-21-84	100	$2,100.00	04-2-13	100	$4,712

COMPUTATION OF INCOME AND EXPENSE FOR UNITS SOLD IN 2013

SABINE ROYALTY TRUST

TAX COMPUTATION WORKSHEET

2013

(RETAIN THIS WORKPAPER AS PART OF YOUR PERMANENT TAX RECORDS)

Part I

INCOME AND EXPENSE

	A			B			C
Item	Number of Units Owned (Note 1)			Income/Expense Per Unit from Appropriate Schedule(s) (Note 2)			Totals		Where to Reflect on 2013 Form 1040 (Note 3)
Gross Royalty Income		100	X	$	.954350	=	$	95.44	Line4, Part I, Schedule E
Severance Tax		100	X	$	.079079	=	$	7.91	Line16, Part I, Schedule E
Interest Income		100	X	$	.000111	=	$	0.01	Line1, Part I, Schedule B
Administrative Expense		100	X	$	.035393	=	$	3.54	Line19, Part I, Schedule E

Part II

COST DEPLETION (Notes 4 and 5)

Assumed Original Basis*			Cost Depletion Allowable in Prior Calendar Years (Note 5)			Adjusted Basis for Cost Depletion Purposes			Appropriate 2013 Cost  Depletion Factor per Depletion Schedule III			2013 Cost Depletion**
$	2,100.00	-	$	2,038.65	=	$	61.35	X		.016971	=	$	1.04

* This number is used for example purposes only. Each Unit holder’s basis is unique to that specific Unit holder.

** Reflect cost depletion on 2013 Form 1040, line 18, Part 1, Schedule E (Note 3).

Part III

COMPUTATION OF GAIN OR (LOSS) FOR UNITS SOLD

Net Sales Price			Adjusted Basis (Note 6)			Gain (Loss)		Where to Reflect on 2013 Form 1040 (Note 3)
$	4,712	-	$	60.31	=	$	4,651.69	Form 4797, Part III, Lines 19-24 and Schedule D

See Page 21 for Applicable Notes.

(SRT 2013 TAX)

23

COMPREHENSIVE EXAMPLE 3

The following example illustrates the computations necessary for an individual to determine income and expenses and gain or loss on Units acquired and disposed of during 2013. The factors in this example are located at the intersection of April and September on the appropriate tables (i.e., the first and last month of 2013 in which Units were owned on monthly Record Dates).

Acquisition Date	Units Acquired	Original Basis	Sales Date	Units Sold	Sales Price
03-30-13	100	$2,100.00	10-01-13	100	$3,000.00

COMPUTATION OF INCOME AND EXPENSE FOR UNITS SOLD IN 2013

SABINE ROYALTY TRUST

TAX COMPUTATION WORKSHEET

2013

(RETAIN THIS WORKPAPER AS PART OF YOUR PERMANENT TAX RECORDS)

Part I

INCOME AND EXPENSE

	A			B			C
Item	Number of Units  Owned (Note 1)			Income/Expense Per Unit from Appropriate Schedule(s) (Note 2)			Totals		Where to Reflect on 2013 Form 1040 (Note 3)
Gross Royalty Income		100	X	$	2.359735	=	$	235.97	Line4, Part I, Schedule E
Severance Tax		100	X	$	.177068	=	$	17.71	Line16, Part I, Schedule E
Interest Income		100	X	$	.000261	=	$	.03	Line1, Part I, Schedule B
Administrative Expense		100	X	$	.080832	=	$	8.03	Line19, Part I, Schedule E

Part II

COST DEPLETION (Notes 4 and 5)

Assumed Original Basis*			Cost Depletion Allowable  in Prior Calendar Years (Note 5)			Adjusted Basis for Cost Depletion Purposes			Appropriate 2013 Cost  Depletion Factor per Depletion Schedule D-I			2013 Cost Depletion**
$	2,100.00	-	$	0.00	=	$	2,100.00	X		.065817	=	$	138.22

* This number is used for example purposes only. Each Unit holder’s basis is unique to that specific Unit holder.

** Reflect cost depletion on 2013 Form 1040, line 18, Part 1, Schedule E (Notes 4 and 5).

Part III

COMPUTATION OF GAIN OR (LOSS) FOR UNITS SOLD

Net Sales Price			Adjusted Basis (Note 6)			Gain (Loss)		Where to Reflect on 2013 Form 1040 (Note 3)
$	3,000.00	-	$	1,961.78	=	$	1,038.22	Form 4797, Part II, Line 10 and Schedule D

See Page 21 for Applicable Notes.

(SRT 2013 TAX)

24

SABINE ROYALTY TRUST HISTORICAL TAX WORKSHEET

	GROSS INCOME		WINDFALL PROFIT TAX		SEVERANCE TAX		NET ROYALTY PMTS		INTEREST INCOME		ADMIN. EXPENSE		MISC. INCOME/ EXPENSE		NET CASH DISTRIB
1983		2.721361		0.316613		0.155445		2.249303		0.019377		0.086800		0.000000		2.181880
1984		3.496106		0.323679		0.196022		2.976405		0.031846		0.155652		0.000000		2.852599
1985		2.853378		0.190767		0.171256		2.491355		0.021277		0.169099		-0.005487		2.338046
1986		1.807003		0.041149		0.114513		1.651341		0.012242		0.184580		0.005487		1.484490
1987		1.648950		0.000209		0.095558		1.553183		0.010601		0.127094		0.000000		1.436690
1988		1.556021		0.000077		0.101561		1.454383		0.010753		0.098526		0.000000		1.366610
1989		1.594196		0.000028		0.131330		1.462838		0.013627		0.096295		0.000000		1.380170
1990		1.748059		0.000000		0.155821		1.592238		0.014058		0.075026		0.000000		1.531270
1991		1.810596		0.000000		0.188955		1.621641		0.010622		0.084643		0.000000		1.547620
1992		1.556025		0.000000		0.132087		1.423938		0.005520		0.135228		0.000000		1.294230
1993		1.751674		0.000000		0.126197		1.625477		0.005316		0.169163		0.000000		1.461630
1994		1.422338		0.000000		0.094300		1.328038		0.005172		0.135390		0.000000		1.197820
1995		1.257833		0.000000		0.086219		1.171614		0.007424		0.151878		0.000000		1.027160
1996		1.650891		0.000000		0.102044		1.548847		0.009748		0.187465		0.000000		1.371130
1997		1.955335		0.000000		0.144324		1.811011		0.010812		0.177263		0.000000		1.644560
1998		1.937789		0.000000		0.123769		1.814020		0.011159		0.171521		0.000000		1.653658
1999		1.663391		0.000000		0.115700		1.547691		0.008112		0.148838		0.000000		1.406965
2000		2.586743		0.000000		0.157354		2.429389		0.016044		0.170794		0.000000		2.274639
2001		3.240755		0.000000		0.210965		3.029790		0.014627		0.183788		0.000000		2.860629
2002		2.175093		0.000000		0.125845		2.049248		0.003150		0.173568		0.000000		1.878830
2003		2.930078		0.000000		0.214244		2.715834		0.003272		0.196541		0.000000		2.522565
2004		3.277066		0.000000		0.271605		3.005461		0.003421		0.222941		0.000000		2.785941
2005		3.874801		0.000000		0.304563		3.570238		0.011804		0.150250		0.000000		3.431792
2006		4.733425		0.000000		0.376823		4.356602		0.024294		0.144170		0.000000		4.236726
2007		4.334040		0.000000		0.361711		3.972329		0.023849		0.145689		0.000000		3.850489
2008		6.587048		0.000000		0.421450		6.165598		0.020735		0.150146		0.000000		6.036187
2009		3.162408		0.000000		0.218949		2.943459		0.001744		0.153550		0.000000		2.791653
2010		4.153492		0.000000		0.308146		3.845346		0.000306		0.141111		0.000000		3.704541
2011		4.436046		0.000000		0.325610		4.110436		0.000442		0.144662		0.000000		3.966216
2012		4.202320		0.000000		0.345350		3.856970		0.000538		0.156560		0.000000		3.700948
2013		4.375012		0.000000		0.313302		4.061710		0.000727		0.145937		0.000000		3.916500

(SRT 2013 TAX)

25

(This page intentionally left blank.)

SABINE ROYALTY TRUST

DISCUSSION OF TAX CONSIDERATIONS PERTAINING TO THE

OWNERSHIP OF UNITS IN SABINE ROYALTY TRUST

The tax law requires individuals, estates, trusts, closely held C corporations and personal service corporations to categorize income and expense into one of three classes, “active,” “portfolio” or “passive,” based upon the nature of the activity and the involvement of the taxpayer in such activity. Because the Trust is a grantor trust, the Unit holders are deemed to hold the investment in the royalty interests directly and the proper classification of the Trust income and expense will be dependent upon the relevant facts and circumstances of each Unit holder. Generally, income or loss resulting from an interest in the Trust is properly classified as portfolio income and as such can be reported as directed on the tax computation worksheet (page 21). However, under certain limited circumstances a different tax classification may be appropriate. Accordingly, Unit holders should consult their own tax advisor regarding all tax compliance matters related to the Units.

Tax Background and WHFIT Information

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 interests, in certain producing and proved undeveloped oil and gas properties located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas.

Sabine received a private letter ruling from the Internal Revenue Service, dated May 2, 1983 (the “Ruling”), concerning certain tax considerations relevant to the creation and continued existence of the Trust. Pursuant to the Ruling, the Trust is classified for federal income tax purposes as a “grantor trust” and not as an association taxable as a corporation. A grantor trust is not subject to federal income tax. Instead, its beneficiaries (the Unit holders in the case of the Trust) are generally considered to own the trust’s income and principal as though no trust were in existence. A grantor trust simply files an information return reflecting all items of income and/or deductions that will be included in the returns of the beneficiaries. Accordingly, each Unit holder of the Trust is taxable on his pro rata share of the Trust’s income and/or deductions.

The income received or accrued and the deductions paid or incurred by the Trust are deemed to be received or accrued and paid or incurred, respectively, by each Unit holder at the same time as the Trust, which is on each Monthly Record Date. On the basis of both the Trust Agreement and the escrow agreement (discussed below), both cash and accrual basis Unit holders should be considered as realizing income and incurring expenses only on the Monthly Record Dates.

Some Trust Units are held by middlemen, as such term is broadly defined in U.S. Treasury Regulations (and includes custodians, nominees, certain joint owners, and brokers holding an interest for a customer in street name, referred to herein collectively as “middlemen”). Therefore, the Trustee considers the Trust to be a non-mortgage widely held fixed investment trust (“WHFIT”) for U.S. federal income tax purposes. U.S. Trust, Bank of America Private Wealth Management, EIN: 56-0906609, 901 Main Street, 17th Floor, Dallas, Texas 75202, telephone number (214) 209-2400, email address trustee@sbr-sabineroyalty.com, is the representative of the Trust that will provide tax information in accordance with applicable U.S. Treasury Regulations governing the information reporting requirements of the Trust as a WHFIT. Tax information is also posted by the Trustee at www.sbr-sabineroyalty.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

(SRT 2013 TAX)

A-1

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.

Effect of Escrow Arrangement

The assets of the Trust include royalty and mineral interests in certain producing and proved undeveloped oil and gas properties (the “Properties”), which constitute economic interests in gross production of oil, gas and other minerals free of the costs of production. The Properties are located in six states and were not carved out of any of Sabine’s working interests in effecting the distribution. In order to facilitate the administration of the Trust and to avoid the expense and inconvenience of daily reporting to Unit holders, the Properties are subject to an escrow agreement, for which the Trustee currently serves as escrow agent.

Pursuant to the terms of the escrow agreement and the conveyances of the Properties by Sabine, the proceeds of production from the 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 for each calendar month only on the 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 that expenses of the Trust will be incurred and paid only on each Monthly Record Date. Assuming the escrow arrangement is respected for federal income tax purposes and the Trustee, as escrow agent, is able to control the timing of income and expenses, as stated above, both cash and accrual basis Unit holders will be treated as realizing income and incurring expenses only on each Monthly Record Date. The Trustee is treating the escrow arrangement as effective for tax purposes and the accompanying tax information has been presented accordingly.

If the escrow arrangement is not respected for federal income tax purposes, a mismatching of income and deductions could occur between a transferor and a transferee upon the sale or exchange of Units. In addition, the Trustee would be required to report the proceeds from production, interest income thereon, and any deductions to the Unit holders on a daily basis, resulting in a substantial increase in the administrative expenses of the Trust.

Depletion

Cost Depletion

Pursuant to the Ruling, each Unit holder is entitled to deduct cost depletion with respect to his pro rata interest in the Properties. A Unit holder’s cost depletion deduction is computed by reference to the Unit holder’s adjusted basis in each of his Units.

The deduction for cost depletion must be computed by a Unit holder with respect to each separate property in the Trust. A Unit holder’s tax basis in each separate property generally must be determined at the time each Unit is acquired by allocating such Unit holder’s cost in each Unit among all properties in the Trust based on their relative fair market values. However, a corporate Unit holder that acquired Units in the distribution from Sabine must determine its tax basis in each separate property in the Trust at the time of the distribution by reference to Sabine’s tax basis in each separate property included in the distribution. The cost depletion deduction attributable to each separate property is calculated for a taxable year by multiplying the tax basis of the property times the appropriate factor reported herein. The factors are derived by dividing total estimated equivalent units of production (barrels of oil and MCF’s of gas) expected to be recovered from the property as of the beginning of the taxable year by the number of equivalent units produced and sold from such property during the taxable year. The resulting deduction for cost depletion cannot exceed the adjusted tax basis in the property. The composite depletion factors presented herein were derived in a manner that encompasses this separate property concept.

(SRT 2013 TAX)

A-2

Percentage Depletion

The Revenue Reconciliation Act of 1990 repealed the rules denying percentage depletion to a transferee of a proven oil or gas property for transfers after October 11, 1990. Because substantially all of the properties were “proven properties” on the date of the original distribution, the percentage depletion deduction has limited applicability to Unit holders who became Unit holders prior to October 12, 1990.

A computation of percentage depletion has been made with respect to the post October 11, 1990 transfers. For some Unit holders, percentage depletion may exceed cost depletion. In such case, a Unit holder is entitled to a percentage depletion deduction in lieu of a cost depletion deduction. Percentage depletion will continue to be computed and compared to cost depletion on an annual basis for Unit holders that acquired their Units via applicable transfers occurring after October 11, 1990.

Adjustment to Basis

Each Unit holder should reduce his tax basis (but not below zero) in the Properties (and correspondingly, his Units) by the amount of cost depletion and percentage depletion allowable with respect to the Properties and by the amount of any return of capital.

Non-Passive Activity Income, Credits and Loss

The income and expenses of the Trust will not be taken into account in computing the passive activity losses and income under Section 469 of the Code for a Unit holder who acquires and holds Units as an investment and not in the ordinary course of a trade or business.

Revenue/Expense and Depletion Calculators

For your convenience, simple revenue/expense and cost depletion calculators are now available on the Sabine Royalty Trust website at: www.sbr-sabineroyalty.com, on both the “Home” page and the “Tax Information” page.

Nonresident Foreign Unit Holders

Nonresident alien individual and foreign corporation Unit holders (“Foreign Taxpayer(s)”), in general, are subject to tax on the gross income attributable to the Trust at a rate equal to 30 percent (or the lower rate under any applicable treaty) without any deductions. This 30 percent tax applies to U.S. source income that is not effectively connected with a U.S. trade or business. Different tax rates and rules apply to income effectively connected with a U.S. trade or business, and those rules are not discussed herein. The 30 percent tax is withheld by the Trust and remitted directly to the United States Treasury. Foreign Taxpayers who have had tax withheld in 2013 should have received a Form 1042-S from the Trust. The Form 1042-S will reflect the total federal income tax withheld from distributions. To avoid double inclusion, the amount reported on the Form 1042-S should not be included as additional income in computing taxable income, as such amount is already included in the per Unit income items on the income and expense schedules included herein. The federal income tax withheld, as reported on the Form 1042-S, should be considered as a credit by the Unit holder in computing any federal income tax liability.

A Foreign Taxpayer holding income producing real property may elect to treat the income from such real property as effectively connected with the conduct of a United States trade or business. As discussed above, different tax rates and rules apply to Foreign Taxpayers with income effectively connected with a U.S. trade or business and those rules are not discussed in detail herein. The income

(SRT 2013 TAX)

A-3

attributable to the Properties is considered income produced from real property. Therefore, this election should be available to Foreign Taxpayers with respect to the taxable income resulting from the ownership of Units. A Unit holder so electing is entitled to claim all deductions with respect to such income but must file a United States income tax return to claim such deductions. In the case of a Foreign Taxpayer that is a foreign corporation, a “branch profits tax” may be imposed at a 30 percent rate (or a lower rate under an applicable treaty). This election, once made, is generally irrevocable unless an application for revocation is approved by the Internal Revenue Service or an applicable treaty allows the election to be made periodically.

Pursuant to the Foreign Investment in Real Property Tax Act of 1980, as amended (“FIRPTA”), a foreign taxpayer is subject to U.S. income tax with respect to the sale, transfer, or disposition of a United States real property interest. FIRPTA generally treats interests in trusts owning United States real property as United States real property interests. However, Foreign Taxpayers with a 5% or less interest in the Trust are not considered to hold U.S. real property interests with respect to the Units because the Units are publicly traded. If the FIRPTA provisions apply because a Foreign Taxpayer holds a greater than 5% interest in the Trust, income tax is required to be withheld from any proceeds distributed to Foreign Taxpayers at the rate of 10% of the amount realized by Foreign Taxpayers upon the sale, exchange or other disposition of a Unit. In addition, distributions, if any, that represent the Foreign Taxpayer’s allocable share of gain realized upon the sale, exchange or other disposition of United States real property interest by the Trust will generally be subject to withholding tax at a 35% rate. The federal income tax withheld under FIRPTA should be considered a credit by the Foreign Taxpayer in computing any federal income tax liabilities.

In order to avoid withholding under FIRPTA, Foreign Taxpayers will be required to furnish the applicable withholding agent with an exemption certificate certifying why such withholding is not required.

Foreign Taxpayers are encouraged to consult their own tax advisors concerning the tax consequences of their investment in the Trust.

Sale or Exchange of Units

Generally, a Unit holder realizes gain or loss upon the sale or exchange of any Unit measured by the difference between the amount realized from the sale or exchange and the adjusted tax basis of such Unit. The adjusted tax basis of a Unit is the original basis of such Unit reduced by depletion deductions allowable (whether deducted or not) with respect to such Unit and by any purchase price adjustment that constitutes a return of capital. Trust income allocable to such Unit is taxable to the selling Unit holder until the date of sale. The purchaser of a Unit is taxable on Trust income allocable to such Unit from the date of purchase forward. For federal income tax purposes, Trust income should generally be allocable only to the holder of record of a Unit on each Monthly Record Date.

For federal income tax purposes, the sale of a Unit will be treated as a sale by a Unit holder of his interest in a royalty interest. Gain or loss on the sale of Units by a 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 the depletion recapture amount. The depletion recapture amount is ordinary income and equals the lesser of (1) the gain on such sale attributable to the disposition of the royalty interest, or (2) the sum of the prior depletion deductions taken with respect to the royalty interests (but not in excess of the initial basis of such Units allocated to the royalty interests).

Backup Withholding

A payor is required under specified circumstances to withhold tax at the rate of 28 percent on “reportable interest or dividend payments” and “other reportable payments” (including certain oil and gas royalty payments). Generally, this “backup withholding” is required on payments if the payee has failed to furnish the payor a taxpayer identification number or if the payor is notified by the Secretary of the Treasury to withhold taxes on such payments with respect to the payee.

(SRT 2013 TAX)

A-4

Amounts withheld by payors pursuant to the backup withholding provisions are remitted to the Internal Revenue Service and are considered a credit against the payee’s federal income tax liability. If the payee does not incur a federal income tax liability for the year in which the taxes are withheld, the payee will be required to file the appropriate income tax return to claim a refund of the taxes withheld.

State Tax

Unit holders may be required to file state tax returns and may be liable for state tax as a result of their ownership of Trust Units. The Properties are located in Florida, Louisiana, Mississippi, New Mexico, Oklahoma and Texas. The tax information included in this booklet is presented in a manner to enable Unit holders to compute the income and deductions of the Trust attributable to each of these states. Unit holders will need this information to comply with the state tax filing requirements in those states imposing a tax. The laws pertaining to tax in any given state may vary from those of another state and from those applicable to federal income tax. Accordingly, Unit holders should consult their own tax advisors concerning state tax compliance matters relating to ownership of Units.

The Trustee has been informed that certain states have contacted Unit holders regarding underpayments of the state tax imposed on the Unit holders’ income from the Trust. Failure by Unit holders to report their state tax liability properly could result in the direct withholding of state taxes from Trust distributions. Accordingly, Unit holders are urged to review carefully the various filing requirements of the states in which the Properties are located to determine if a state tax liability exists as a result of the ownership of Units in the Trust.

Florida does not have a personal income tax. Florida imposes an income tax on resident and nonresident corporations (except for S corporations not subject to the built-in-gains tax or passive investment income tax), which will be applicable to royalty income allocable to a corporate Unit holder from Properties located within Florida.

Louisiana, Mississippi, New Mexico, and Oklahoma each impose taxes 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 be applicable to royalty income allocable to a Unit holder from Properties located within those states. Even though there are variances from state to state, taxable income for state tax purposes is often computed in a manner similar to the computation of taxable income for federal income tax purposes.

New Mexico and Oklahoma impose a withholding tax on payments 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 has filed New Mexico and Oklahoma tax returns, obtained a refund, and distributed that refund 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 as withholding at the Trust level reduces the amount of cash available for distribution; 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.

Texas imposes a franchise tax on generally all entity types providing limited liability protection at a rate of 1% 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 that provide 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

(SRT 2013 TAX)

A-5

non-operated mineral interest income, and do not receive more than 10% of their income from operating an active trade or business generally are 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 considered a taxable entity under the Texas franchise tax will generally be required to include its portion of Trust revenues in its own Texas franchise tax computation. This revenue is sourced to Texas under provisions of the Texas Administrative Code sourcing such income according to the principal place of business of the Trust, which is Texas.

All states have not adopted federal law with respect to the percentage method of computing depletion nor are such methods consistent among the various states. It should be noted, however, that cost depletion generally is allowed by those states in which the properties are located (Unit holders should note that a special depletion rule applies in Oklahoma). Information is included previously within this booklet to assist you in determining the respective allowable cost depletion deductions by state.

Unit holders should consult their own tax advisors concerning the type of state tax returns that may be required and their applicable due dates.

(SRT 2013 TAX)

A-6

Following is a list of names and addresses of the various state taxing authorities from which you may obtain additional information:

Florida		Florida Department of Revenue
		5050 W. Tennessee Street
		Tallahassee, Florida 32399-0100
		(800) 352-3671
		www.myflorida.com/dor/taxes
New Mexico	Individuals:	State of New Mexico
		Taxation and Revenue Department
		1100 South Saint Francis Drive
		P.O. Box 25122
		Santa Fe, New Mexico 87504-5122
		(505) 827-0700, (505) 827-0951
		www.tax.state.nm.us
	Corporations:	New Mexico Taxation and Revenue Department
		Attention: Corporate Income and Franchise Tax
		P.O Box 25127
		Santa Fe, New Mexico 87504-5127
		(505) 827-0825
		www.tax.state.nm.us
Mississippi		Mississippi Department of Revenue
		P.O. Box 1033
		Jackson, Mississippi 39215-1033
		(601) 923-7000
		www.dor.ms.gov
Louisiana	Individuals:	Department of Revenue and Taxation
		State of Louisiana
		P.O Box 201
		Baton Rouge, Louisiana 70821
		(225) 219-0102
		www.rev.state.la.us
	Corporations:	Secretary of Revenue and Taxation
		State of Louisiana
		P.O. Box 201
		Baton Rouge, Louisiana 70821
		(225) 219-7462
		www.rev.state.la.us
Oklahoma	Individuals:	Oklahoma Tax Commission
		P.O. Box 26800
		Oklahoma City, OK 73126-0800
		(405) 521-3160
		www.oktax.state.ok.us
	Corporations:	Oklahoma Tax Commission
		P.O. Box 26800
		Oklahoma City, Oklahoma 73126-0800
		(405) 521-3126
		www.oktax.state.ok.us
Texas		Texas Comptroller of Public Accounts
		P.O. Box 13528, Capitol Station
		Austin, Texas 78711-3528
		(800) 252-5555
		www.window.state.tx.us

(SRT 2013 TAX)

A-7

(This page intentionally left blank.)

(This page intentionally left blank.)

TAX INFORMATION

2013

Sabine Royalty Trust

P.O. Box 830650

Dallas, Texas 75283-0650

U.S. Trust, Bank of America Private Wealth Management, Trustee

1-800-365-6541

fax 214-209-2431

www.sbr-sabineroyalty.com

EX-99.2

Exhibit 99.2

Report of Independent Registered Public Accounting Firm

To the Management of the Trustee on Behalf of Unit holders of Sabine Royalty Trust:

We have audited the accompanying Statements of Fees and Expenses (as defined in Exhibit C to the Sabine Royalty Trust Agreement) paid by Sabine Royalty Trust to Bank of America, N.A., (the “Trustee”), as trustee and escrow agent, for the years ended December 31, 2013, 2012 and 2011. These statements are the responsibility of the Trustee’s management. Our responsibility is to express an opinion on these statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the Statements of Fees and Expenses are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the Statements of Fees and Expenses. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall statement presentation. We believe that our audits provide a reasonable basis for our opinion.

As described in Note 3, the Statements of Fees and Expenses 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.

In our opinion, the Statements of Fees and Expenses referred to above present fairly, in all material respects, the fees and expenses paid by Sabine Royalty Trust to Bank of America, N.A., as trustee and escrow agent, for the years ended December 31, 2013, 2012 and 2011, on the basis of accounting described in Note 3.

/s/ PricewaterhouseCoopers LLP

Dallas, Texas

March 3, 2014

STATEMENTS OF FEES AND EXPENSES

PAID BY SABINE ROYALTY TRUST TO

BANK OF AMERICA, N.A., AS

TRUSTEE AND ESCROW AGENT, FOR EACH OF THE THREE

YEARS IN THE PERIOD ENDED DECEMBER 31, 2013

	2013		2012		2011
Trustee’s fee	$	295,294	$	325,148	$	317,119
Escrow agent’s fee		885,863		975,435		951,336
Total fees and expenses		1,181,157		1,300,583		1,268,455

The accompanying notes are an integral part of these statements.

Notes

1. Sabine Royalty Trust (the “Trust”) is an express trust formed under the laws 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 (“Sabine”), as trustor, and Bank of America, N.A. (the “Bank”), as successor trustee (the “Trustee”). Contemporaneously with the execution of the Trust Agreement, Sabine, the Trustee and the predecessor of the Bank, as escrow agent (the “Escrow Agent”), entered into an escrow agreement which establishes an escrow (the “Escrow”). Prior to distribution of units of beneficial interest (the “Units”) in the Trust to Sabine’s shareholders, Sabine transferred to the Trust royalty and mineral interests, including landowner’s royalties, overriding royalty interests, minerals (other than executive rights, bonuses and delay rentals), production payments and other similar, non-participatory interests, in certain producing and proved undeveloped oil and gas properties in six states (the “Royalty Properties”).

In May 1988, Sabine was acquired by Pacific Enterprise (“Pacific”), 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, 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 compensation agreement under the Trust Agreement provides for a “cost plus” fee payable to the Bank for all services rendered in its capacities as Trustee and as Escrow Agent. Generally, the fees payable to the Bank are calculated by dividing the expenses incurred by the Bank, as Trustee and as Escrow Agent, solely for services provided by the Bank in the administration of the Trust and the Escrow by seven-tenths (0.7). Professional and other noncontributing (out-of-pocket) expenses incurred by the Bank, as Trustee or as Escrow Agent, as the case may be, in the performance of its duties in the foregoing capacities are charged to the Trust or the Escrow, as the case may be, at cost. These expenses do not contribute to the fees payable to the Bank described above. Annually, the Trustee must estimate Trust and Escrow expenses contributing to the fee for the forthcoming year and publish this amount in the Trust’s first quarterly report to Unit holders. The Trustee can be penalized by forfeiture of reimbursement for part of its expenses if such expenses exceed the estimate. The Trustee also can earn a bonus by administering the Trust for total costs that are lower than the estimate. The Bank elected to forego bonuses earned of $69,595, $79,417 and $111,545 in 2013, 2012 and 2011, respectively.

2. Escrow Agent’s fees and Trustee’s fees consist of a profit margin plus all fully allocated costs incurred by the Bank, as Trustee and as Escrow Agent, in performing administrative services to the Trust as specified in the Trust Agreement. Allocated costs do not include any professional and related expenses paid to third parties.

All costs incurred by the Bank in its capacities as Trustee and as Escrow Agent are accumulated in one account. Fees based thereon are allocated between the Trustee function and the Escrow Agent function according to the actual administrative services rendered by the Bank in each capacity. Any determinations by the Bank as to the allocation of the fee between the Trustee and the Escrow Agent are conclusive and binding on the Unit holders and Pacific (USA), but in no event does the Bank’s allocation affect the aggregate fee payable to the Bank.

3. The Statements of Fees and Expenses are prepared on a modified cash basis, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America. Trust expenses 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. These statements differ from statements prepared in conformity with accounting principles generally accepted in the United States of America because expenses other than those expected to be paid on the following monthly record date are not accrued.

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.

4. On January 9, 2014, U.S. Trust, Bank of America Private Wealth Management gave notice to Unit holders that it will be resigning as Trustee subject to the conditions set forth below. Bank of America, N.A. intends to nominate Southwest Bank, an independent state bank chartered under the laws of the State of Texas and headquartered in Fort Worth, Texas (“Southwest Bank”), as successor trustee at a meeting of Unit holders of the Trust to be called for the purpose of approving a successor trustee of the Trust. U.S. Trust, Bank of America Private Wealth Management’s resignation is conditioned on the satisfaction or waiver by U.S. Trust, Bank of America Private Wealth Management of each of the following: (i) the appointment of Southwest Bank as trustee of the Trust; (ii) the appointment of Southwest Bank or another successor trustee as trustee of six other royalty trusts for which U.S. Trust, Bank of America Private Wealth Management currently serves as trustee and as agent under a disbursing arrangement for which it currently serves as agent; (iii) the accuracy of certain representations and warranties and performance of certain agreements made by Southwest Bank in an agreement between U.S. Trust, Bank of America Private Wealth Management and Southwest Bank; and (iv) no governmental injunction, order or other action that would prohibit Southwest Bank’s appointment, U.S. Trust, Bank of America Private Wealth Management’s resignation or the other actions described above. The effective date of U.S. Trust, Bank of America Private Wealth Management’s resignation shall be May 30, 2014, assuming all of the conditions described above have been satisfied or waived as of such date.