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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, 2005

o		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 Bank of America, N.A. Bank of America Plaza 17th Floor 901 Main Street Dallas, Texas (Address of principal executive offices)		75202 (Zip Code)

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

Securities registered pursuant to Section 12(b) of the Act:


		Name of Each Exchange
Title of Each Class		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 o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes o 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 o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one):

Large accelerated filer o Accelerated filer x Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule b-2 of the Act). Yes o 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 $617 million.

At March 6, 2006, 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		2
	Liabilities of Trustee		3
	Duration of Trust		3
	Voting Rights of Unit Holders		3
	Description of Units		4
	Distributions of Net Income		4
	Transfer		4
	Reports to Unit Holders		5
	Liability of Unit Holders		5
	Possible Divestiture of Units		5
	Federal Taxation		6
	State Tax Considerations		8
	Regulation and Prices		9
	Regulation		9
	Prices		10
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		14
Item 2.	Properties		14
	Title		15
	Reserves		15
Item 3.	Legal Proceedings		20
Item 4.	Submission of Matters to a Vote of Security Holders		20
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters and Issuer Purchases of Equity Securities		21
Item 6.	Selected Financial Data		21
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		21
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		25
Item 8.	Financial Statements and Supplementary Data		26
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		39
Item 9A.	Controls and Procedures		39
Item 9B.	Other Information		42
PART III
Item 10.	Directors and Executive Officers of the Registrant		42
Item 11.	Executive Compensation		42
Item 12.	Security Ownership of Certain Beneficial Owners and Management		42
Item 13.	Certain Relationships and Related Transactions		42
Item 14.	Principal Accounting Fees and Services		42
PART IV
Item 15.	Exhibits, Financial Statement Schedules		43
Consent of DeGolyer and MacNaughton
Rule 13a-14(a)(15d-14(a)) Certification
Certification Pursuant to Section 906
Report - Interim Tax Information

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. 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.

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 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, and accounting, engineering, legal and other professional fees. The total general and administrative expenses of the Trust for 2005 were $2,089,547 of which, pursuant to the terms of the Trust Agreement, $297,187 was paid to Bank of America, as Trustee, and $891,548 was paid to Bank of America, 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 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 March 6, 2006, there were 14,579,345 Units outstanding.

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

Distributions of Net Income

The identity of Unit holders entitled to receive distributions of Trust income and the amounts thereof are determined as of each Monthly Record Date. Unit holders of record as of the Monthly Record Date (the 15th day of 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. See “Item 1 — State Law and Tax Considerations.”

Mellon Investor Services LLC serves as 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.

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.

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. A Unit holder generally would not have claimed percentage depletion deductions for 1990 or any subsequent year because cost depletion generally has exceeded percentage depletion.

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”) (discussed above), the taxpayer generally must recapture the amount deducted for depletion in 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 United States 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 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 did not acquire them 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 deduct “miscellaneous itemized deductions” (including, in general, investment expenses) only to the extent that such expenses exceed 2 percent of the individual’s adjusted gross income. Although there are exceptions to the 2 percent limitation, authority suggests that no exceptions apply to expenses passed through from a grantor trust, like the Trust. Unit holders itemizing deductions will also be subject to limitations on taking such deductions if the Unit holder’s adjusted gross income exceeds a threshold amount, which is $145,950 for 2005 and $150,500 for 2006 (if married, filing jointly).

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 INCOME 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 INCOME 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, corporations and limited liability companies doing business in Texas are subject to the Texas franchise tax, which includes a calculation based upon the company’s taxable income for federal income tax purposes (or comparable amounts, in the case of limited liability companies). It is unlikely that the ownership of Units would be sufficient to subject a corporate Unit holder to the franchise tax who is not otherwise doing business in Texas and who does not have control over the Trust or the Trustee of the Trust. Under certain circumstances, Texas inheritance tax may be applicable to property in Texas (including intangible personal property such as the Units) of both resident and nonresident decedents.

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. Units held by residents of Louisiana, to the extent that they represent a proportionate share of mineral royalties from mineral interests located in Louisiana, are subject to Louisiana inheritance and other taxes and probate, community property, forced heirship and other rules. For deaths occurring after June 30, 2004, no Louisiana inheritance tax is due and no inheritance tax return is required if certain requirements are met. Special rules apply for decedents’ estates located in areas impacted by Hurricanes Katrina and Rita of 2005. Units held of record by a person who was not domiciled in Louisiana at the date of death generally are not subject to Louisiana inheritance taxes or probate, community property or forced heirship rules, and Units transferred inter vivos by non-domiciliaries of Louisiana generally are not subject to Louisiana gift tax.

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 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 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, the Trust should be considered a grantor trust for state income tax purposes and 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.

New Mexico imposes 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 will then file a New Mexico tax return, obtain a refund, and distribute 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 the New Mexico tax refund is received by the Trust or after the refund is 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 with the filing of their New Mexico 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, prevention of waste, and 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 often are difficult and costly to comply with and which carry substantial penalties for the failure to comply.

Natural Gas

Prices for the sale of natural gas, like the sale of other commodities, are governed by the marketplace and the provisions of applicable gas sales contracts. The Federal Energy Regulatory Commission (“FERC”), which principally is responsible for regulating interstate transportation and the sale of natural gas, has taken significant steps in the implementation of a policy to restructure the natural gas pipeline industry to promote full competition in the sales of natural gas, so that all natural gas suppliers, including pipelines, can compete equally for sales customers. This policy has been implemented largely through restructuring proceedings and is subject to continuing refinement. The effects of this policy are now presumably fully reflected in the natural gas markets. The current policy of FERC continues to promote

increased competition among gas industry participants. Accordingly, Order 636 and various other 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 nonpipeline suppliers on a competitive basis.

There are many other statutes, rules, regulations and orders that 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.

Prices

Oil

The Trust’s average per barrel oil price increased from $33.78 in 2004 to $40.47 in 2005. The Trustee believes that the international instability all year coupled with increasing global demand and supply shortage concerns led to an increase in the price of oil. This increase was magnified by reduced production as a result of the tropical storms in the Gulf of Mexico in late August and early September. Afterwards oil prices soared to record levels, reaching over $69 per barrel.

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 2005 on natural gas volumes sold of $6.84 per Mcf represented a significant increase from the $4.80 per Mcf received in 2004, due largely to international instability and the tropical storms in the Gulf of Mexico in late August and early September.

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. It is anticipated that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations regulating health, safety, the release of materials into the environment or otherwise relating to the protection of the environment will not have a material adverse effect upon the Trust or Unit holders. The Trustee cannot predict what effect additional regulation or legislation, enforcement policies thereunder, and 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 of compliance could result in wells being plugged and abandoned earlier in their productive lives, with a resulting loss of reserves and revenues to the Trust.

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 and companies that disposed, or arranged for the disposal, of the hazardous substance found at a site. 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 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 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.

New Events

Proxy Solicitation

On January 4, 2006, proxy solicitation materials were mailed to unitholders of record and unitholders who hold the units through brokerage accounts. The solicitation received by unitholders concerns an initiative created by Sabine Production Partners, LP.

Despite the similarity of the name of Sabine Production Partners, LP (“SPP”), it is not an entity that is affiliated with Sabine Royalty Trust (“SRT” or the “Trust”).

In the proposals SPP sets forth in its proxy solicitation, SPP seeks to gain control of the assets of Sabine Royalty Trust by liquidating the Trust in a manner whereby the assets of the Trust are sold to SPP in exchange for partnership interests in SPP that would be distributed to unitholders of the Trust upon its liquidation.

On January 31, 2006, Sabine Production Partners, LP (“SPP”) announced that it is suspending indefinitely its previously-announced solicitation of proxies from unitholders of Sabine Royalty Trust. SPP is not withdrawing or abandoning its Registration Statement or Proxy Statement/ Prospectus. No recommencement of the solicitation will occur without a public announcement to that effect by SPP and the making of appropriate filings with the SEC. Until such announcement and filings, SPP has stated that it will not attempt to call a meeting of SBR unitholders using any proxies that have been submitted prior to recommencement.

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;

	•	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, the war in Iraq 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.

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, 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 in 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 Commission staff regarding its periodic or current reports under the Act within the 180 days preceding December 31, 2005.

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, 2005.


		Mineral and Royalty

State		Gross Acres		Net Acres

Florida			5,448		697
Louisiana			244,391		23,682
Mississippi			75,489		9,713
New Mexico			112,294		9,141
Oklahoma			381,538		67,558
Texas			1,273,132		105,760

	Total		2,092,292		216,551

Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate count of the number of wells located on the Royalty Properties, the number of exploratory or development wells drilled on the Royalty Properties during the periods presented by this report, or the number of wells in process or other present activities on the Royalty Properties, and the Registrant cannot readily obtain such information.

Title

The conveyances of the Royalty Properties to the Trust covered the royalty and mineral properties located in the six states that were vested in Sabine Corporation on the effective date of the conveyances and that were subject to existing oil, gas and other mineral leases other than properties specifically excluded in the conveyances. Since Sabine Corporation may not have had available to it as a royalty owner information as to whether specific lands in which it owned a royalty interest were subject to an existing lease, minimal amounts of nonproducing royalty properties may also have been conveyed to the Trust. Sabine Corporation did not warrant title to the Royalty Properties either expressly or by implication.

Reserves

The Registrant has obtained from DeGolyer and MacNaughton, independent petroleum engineering consultants, a study of the proved oil and gas reserves attributable as of January 1, 2006 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.

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

March 7, 2006

Bank of America, N.A.

P. O. Box 830650

Dallas, Texas 75283-0650

Gentlemen:

Pursuant to your request, we have prepared estimates of the extent and value of the proved crude oil, condensate, natural gas liquids (NGL), and natural gas reserves, as of January 1, 2006, of certain royalty interests owned by Sabine Royalty Trust (the Trust). 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.

Information used in the preparation of this report was obtained from Bank of America, from records on file with the appropriate regulatory agencies, and from public sources. Additionally, this information includes data supplied by Petroleum Information/ Dwights LLC; Copyright 2006 Petroleum Information/ Dwights LLC. During this investigation, we consulted freely with officers and employees of Bank of America and were given access to such accounts, records, geological and engineering reports, and other data as were desired for examination. In the preparation of this report we have relied, without independent verification, upon information furnished by Bank of America with respect to property interests owned by the Trust, production from such properties, 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. It was not considered necessary to make a field examination of the physical condition and operation of the properties in which the Trust owns interests.

Our reserves estimates are based on a detailed study of the properties and were prepared by the use of standard geological and engineering methods generally accepted by the petroleum industry. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, consideration of the stage of development, and the quality and completeness of basic data. 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 41 percent of the total 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.

Reserves estimated in this report are expressed as gross and net reserves. Gross reserves are defined as the total estimated petroleum to be produced from these properties after December 31, 2005. Net reserves are defined as that portion of the gross reserves attributable to the interests owned by the Trust after deducting royalties and other interests held by others. Gas volumes shown herein are sales-gas volumes and are expressed at a temperature base of 60 degrees Fahrenheit and at the legal pressure base of the state in which the interest is located. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Condensate reserves estimated herein are those to be recovered by normal field separation. NGL reserves are those attributed to the leasehold interests according to processing agreements.

Petroleum reserves included in this report are classified by degree of proof as proved and 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 expenses as of the date the estimate is made, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. Proved reserves classifications used in this report are in accordance with the reserves definitions of Rules 4-10(a) (1)-(13) of Regulation S-X of the Securities and Exchange Commission (SEC) of the United States. The petroleum reserves are classified as follows:

Proved oil and gas reserves — Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and expenses as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.


	(i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

	(ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

	(iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite, and other such sources.


	Proved developed oil and gas reserves — Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery should be included as “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

	Proved undeveloped reserves — Proved undeveloped oil and gas reserves are reserves 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. Reserves on undrilled acreage shall be limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive formation. Under no circumstances should estimates for proved 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 tests in the area and in the same reservoir.

The development status shown herein represents the status applicable on January 1, 2006. In the preparation of this study, data available from wells drilled on the appraised properties through October 31, 2005, were used in estimating gross ultimate recovery. When applicable, gross production estimated to January 1, 2006, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of January 1, 2006. In some fields, this required that the production rates be estimated for up to 4 months, since production data were available only through August 2005.

Estimated net proved reserves, as of January 1, 2006, attributable to the Trust from the properties appraised are summarized in thousands of barrels (Mbbl) or millions of cubic feet (MMcf) as follows:


	Proved Developed Reserves				Proved Undeveloped Reserves

	Oil, Condensate,				Oil, Condensate,
	and NGL		Sales Gas		and NGL		Sales Gas
State	(Mbbl)		(MMcf)		(Mbbl)		(MMcf)

Florida		153		20		0		0
Louisiana		74		505		0		0
Mississippi		101		2,134		30		228
New Mexico		470		3,469		0		0
Oklahoma		559		9,969		0		0
Texas		4,840		20,075		41		2

Total		6,197		36,172		71		230

Revenue values in this report are expressed in terms of estimated future net revenue and present worth of future net revenue. These values are based on the continuation of prices in effect on January 1, 2006. Future gross revenue is defined as that revenue to be realized from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting estimated severance and ad valorem taxes from the future gross revenue. Present worth of future net revenue is calculated by discounting the future net revenue at the arbitrary rate of 10 percent per year compounded monthly over the expected period of realization.

Revenue values in this report were estimated using the initial prices and expenses provided by Bank of America. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The initial and future prices used in this report are adjusted to prices on January 1, 2006, based on receipts by the Trust in December 2005. The assumptions used for estimating future prices and expenses are as follows:


	Oil, Condensate, NGL, and Natural Gas Prices

Oil, condensate, NGL, and natural gas prices, based on receipts by the Trust in December 2005, were furnished by Bank of America. These prices were adjusted to the NYMEX posted prices for oil of $60.32 per barrel and for gas of $10.06 per million British thermal units, and were held constant for the lives of the properties. The weighted average prices over the lives of the properties were $53.65 per barrel of oil and $8.64 per thousand cubic feet.


	Expenses

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.

A projection of the estimated future net revenue from the properties appraised, as of January 1, 2006, based on the aforementioned assumptions concerning prices and expenses is summarized as follows, expressed in thousands of dollars (M$):


	Future Net
	Revenue
Year Ending December 31	(M$)

2006		57,555
2007		50,429
2008		44,812

Subtotal		152,796
Remaining		413,281

Total		566,077

The present worth, at a discount rate of 10 percent, of future net revenue, as of January 1, 2006, is estimated to be M$287,777.

Estimates of oil, condensate, NGL, and 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.

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 10-13, 15 and 30(a)-(b) of Statement of Financial Accounting Standards No. 69 (November 1982) of the FASB and Rules 4-10(a) (1)-(13) of Regulation S-X and Rule 302(b) of Regulation S-K of the SEC; provided, however, that (i) certain estimated data have not been provided with respect to changes in reserves information, (ii) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein, 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 thereof for certain royalty interests accounting for approximately 41 percent of the Trust’s total proved reserves have been estimated in the aggregate by state or field 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.

To the extent that the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature or information beyond the scope of our report, we are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.


	Submitted,

	DeGOLYER and MacNAUGHTON

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

	Paul J. Szatkowski, P.E.
	Senior Vice President
	DeGolyer and MacNaughton

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 2006 will be approximately $2,280,000.

The present value of future net revenue of the Trust’s proved developed reserves increased from $194,229,373 at January 1, 2005 to $289,141,236 at January 1, 2006. This increase resulted primarily from the gas prices used in the calculation of such amount, from $5.66 per Mcf of gas at January 1, 2005 to $8.64 per Mcf of gas at January 1, 2006, as well as an increase in the price of oil from $39.14 per barrel of oil at January 1, 2005 to $53.65 per barrel of oil at January 1, 2006.

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 March 6, 2006, the NYMEX posted oil price was approximately $62.41 per barrel, which compared to the posted price of $60.32 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 March 6, 2006, the NYMEX posted gas price was $6.49 per million British thermal units. The use of such price, as compared to the posted price of $10.06 per million British thermal units, used to calculate the future net revenue to the Trust’s proved developed reserves would result in a smaller 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. Submission of Matters to a Vote of Security Holders.

Not applicable.

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
2005	High		Low		per Unit

First Quarter	$	42.97	$	34.71	$	0.69653
Second Quarter		42.86		36.70		0.83104
Third Quarter		51.99		42.35		0.90890
Fourth Quarter		52.49		40.21		0.99533


	Sales Price
					Distributions
2004	High		Low		per Unit

First Quarter	$	32.75	$	26.40	$	0.60479
Second Quarter		36.42		30.20		0.71585
Third Quarter		40.63		33.55		0.75767
Fourth Quarter		42.49		33.60		0.70763

At March 7, 2006, there were 14,579,345 Units outstanding and approximately 2,047 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	2005		2004		2003		2002		2001

Royalty Income	$	54,594,978	$	42,338,724	$	38,761,739	$	28,134,458	$	44,222,701
Distributable Income		52,680,811		40,587,685		37,060,003		26,539,751		42,805,378
Distributable Income per Unit		3.61		2.78		2.54		1.82		2.94
Total Assets at Year End		7,371,124		4,912,815		5,555,045		5,391,280		5,855,378
Distributions per Unit		3.43		2.79		2.52		1.88		2.86

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

Liquidity and Capital Resources

Sabine Royalty Trust (the “Trust”) makes monthly distributions to its Unit holders of the excess of the preceding month’s revenues received over expenses incurred. Upon receipt, royalty income is invested in short-term investments until its subsequent distribution. In accordance with the Trust Agreement, the Trust’s only long-term assets consist of royalty interests in producing oil and gas properties. Although the Trust is permitted to borrow funds if necessary to continue its operations, borrowings are not anticipated in the foreseeable future. Accordingly the Trust is dependent on its operations to generate excess cash flows utilized in making distributions. These operating cash flows are largely dependent on such factors as oil and gas prices and production volumes, which are influenced by many factors beyond the control of the Trust. As a royalty owner, the Trust does not have access to certain types of information that would be disclosed by

a company with oil and gas operations. See “Item 2. Properties” for a discussion of the types of information not available to the Trust.

The amount to be distributed to Unit holders (“Monthly Income Amount”) is determined on a monthly basis. The Monthly Income Amount is an amount equal to the sum of cash received by the Trust during a monthly period (the period commencing on the day after a monthly record date and continuing through and including the next succeeding monthly record date) attributable to the Royalty Properties, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. Unit holders of record as of the monthly record date (the 15th day of each calendar month, except in limited circumstances) are entitled to have distributed to them the calculated Monthly Income Amount for such month on or before 10 business days after the monthly record date. The Monthly Income Amount per Unit is declared by the Trust no later than 10 days prior to the monthly record date. The cash received by the Trust is primarily from purchasers of the Trust’s oil and gas production and consists of gross sales of production less applicable severance taxes.

Results of Operations

Distributable income consists of royalty income plus interest income plus any decrease in cash reserves established by the Trustee less general and administrative expenses of the Trust less any increase in cash reserves established by the Trustee. The Trust’s royalty income represents payments received during a particular time period for 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 2004 and 2005.

Net royalty income during 2005 increased approximately $12,256,000, or 28.9 percent, compared to 2004 net royalty income, which had increased approximately $3,577,000, or 9.2 percent, from 2003 net royalty income.

Revenues generated by sales of oil and gas increased in 2005 from 2004 as a result of higher gas and oil prices along with increased oil volumes. These increases were tempered by a decrease in natural gas volumes. Gas volumes decreased from 6,029,402 thousand cubic feet (“Mcf”) in 2004 to 5,255,624 Mcf in 2005 after decreasing from 6,532,013 Mcf in 2003. The average price per Mcf of gas received by the Trust increased from $4.80 per Mcf in 2004 to $6.84 per Mcf in 2005, after increasing from $4.39 per Mcf in 2003. The Trustee believes that normal market forces, international instability, and the tropical storms in late August and early September, 2005 resulted in the higher gas prices.

Oil volumes sold increased to 603,616 barrels in 2005 from 525,862 barrels in 2004, having decreased from 577,087 barrels in 2003. The effect of this volume increase was enhanced by an increase in the average price per barrel received by the Trust to $40.47 in 2005 from $33.78 in 2004, which was an increase from $26.17 in 2003. The Trustee believes that international instability along with tropical storms in late August and early September resulted in the increase in price for 2005.

Interest income increased to $175,000 in 2005 from $51,000 in 2004, which increased from $47,000 in 2003. Changes in interest income are the result of changes in interest rates and funds available for investment. General and administrative expenses increased to $2,090,000 in 2005 compared to $1,802,000 in 2004 due primarily to increases in professional fees for Sarbanes-Oxley compliance, increased tax reporting to unitholders, and costs to upgrade the financial reporting of approximately $67,000, $56,000 and $37,000, respectively. Other increases included an increase in the trustee/escrow agent fees, legal fees, auditing expenses and printing fees of $23,000, $24,000, $13,000, and $27,000, respectively. General and administrative expenses increased to $1,802,000 in 2004 compared to $1,749,000 in 2003 due mainly to increases in professional fees for Sarbanes-Oxley compliance of approximately $91,000. This increase in professional fees was offset somewhat by decreases in fees related to unitholder information services and tax reporting services of approximately $24,000 and $15,000, respectively.

Contractual Obligations


			Less than						More than
Contractual Obligations	Total		1 Year		1-3 Years		3-5 Years		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.

	•	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

Independent petroleum engineers estimate the net proved reserves attributable to the royalty interests. In accordance with Statement of Financial Standards No. 69, “Disclosures About Oil and Gas Producing Activities,” estimates of future net revenues from proved reserves have been prepared using year-end contractual gas prices and related costs. 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, 2005.

New Accounting Pronouncements

SFAS No. 123R, “Accounting for Stock-Based Compensation” was issued in December 2004 and provides new implementation guidance for stock-based compensation accounting. This Statement is effective for public entities that do not file as small business issuers — as of the beginning of the first interim or annual reporting period that begins after June 15, 2005. The Trust has no options or other stock-based instruments and accordingly, this new Standard will have no impact on the financial statements of the Trust.

In May 2005, the FASB issued Statement of Financial Accounting Standards No. 154, “Accounting Changes and Error Corrections — A Replacement of APB Opinion No. 20 and FASB Statement No. 3.” SFAS No. 154 requires retrospective application, or application on the latest practical date, as the preferred method to report a change in accounting principle or correction of an error. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. This new standard has no impact on the financial statements of the Trust.

In March 2005, the FASB issued FASB Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” (“FIN 47”). FIN 47 clarifies the term conditional asset retirement obligation and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation to perform an asset retirement activity; however the timing and/or method of settling the obligation are conditional on a future event that may or may not be within the control of the entity. FIN 47 is effective for fiscal years ending after December 15, 2005. This new standard has no impact on the financial statements of the Trust.

Off-Balance Sheet Arrangements

As stipulated in the Trust Agreement, the Trust is intended to be passive in nature and the Trustee does not have any control over or any responsibility relating to the operation of the Royalty Properties. The Trustee has powers to collect and distribute proceeds received by the Trust and to pay Trust liabilities and expenses, and its actions have been limited to those activities. Therefore, the Trust has not engaged in 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 2003 and 2005. The following table presents the weighted average prices received per year by the Trust:


	Oil		Gas
	Per BBL		Per Mcf

2005	$	40.47	$	6.84
2004		33.78		4.80
2003		26.17		4.39

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,” and certain statements regarding the Trust’s financial position, industry conditions and other matters contained in this Item 7. Although the Trustee believes that the expectations reflected in such forward-looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors identified in this Annual Report affecting oil and gas prices (including, without limitation, the domestic and foreign supply of oil and gas and the price of foreign imports, market demand, the price and availability of alternative fuels, the availability of pipeline capacity, instability in oil-producing regions and the effect of governmental regulations), the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified in Item 1A, “Risk Factors”.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

The Trust is a passive entity, and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short term investments acquired with funds held by the Trust pending distribution to Unit holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit holders to any foreign currency related market risk. The Trust invests in no derivative financial instruments and has no foreign operations or long-term debt instruments.

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

We have audited the accompanying condensed statement of assets, liabilities and trust corpus of Sabine Royalty Trust (the “Trust”) as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005. 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 consolidated financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2005 and 2004, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005, 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 effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 10, 2006 expressed an unqualified opinion on Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting and an unqualified opinion on the effectiveness of the Trust’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Dallas, Texas

March 10, 2006

SABINE ROYALTY TRUST

FINANCIAL STATEMENTS

Statements of Assets, Liabilities and Trust Corpus


	December 31,

	2005		2004

Assets
Cash and short-term investments	$	6,335,822	$	3,753,282
Royalty interests in oil and gas properties less accumulated amortization of $21,359,883 (2005) and $21,235,652 (2004)		1,035,302		1,159,533

Total	$	7,371,124	$	4,912,815


Liabilities And Trust Corpus
Trust expenses payable	$	148,696	$	249,308
Other payables (Note 4)		176,176		140,432

Total liabilities		324,872		389,740
Trust Corpus (14,579,345 units of beneficial interest authorized and outstanding)		7,046,252		4,523,075

Total	$	7,371,124	$	4,912,815

Statements of Distributable Income


	Year Ended December 31,

	2005		2004		2003

Royalty Income	$	54,594,978	$	42,338,724	$	38,761,739
Interest Income		175,380		50,785		47,417

Total		54,770,358		42,389,509		38,809,156
General and administrative expenses (Note 6)		2,089,547		1,801,824		1,749,153

Distributable income	$	52,680,811	$	40,587,685	$	37,060,003

Distributable income per unit (Basic and Assuming Dilution) (14,579,345 units) (Note 1)	$	3.61	$	2.78	$	2.54

Distributions per unit (Note 3)	$	3.43	$	2.79	$	2.52

Statements of Changes in Trust Corpus


	2005			2004			2003

Trust corpus, beginning of year	$	4,523,075		$	4,700,993		$	4,603,219
Amortization of royalty interests		(124,231	)		(148,418	)		(184,950	)
Distributable income		52,680,811			40,587,685			37,060,003
Distributions to unit holders (Note 3)		(50,033,403	)		(40,617,185	)		(36,777,279	)

Trust corpus, end of year	$	7,046,252		$	4,523,075		$	4,700,993

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

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 Exxon Mobil. 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).

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

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

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.

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


	•	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.

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)


	•	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.

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.

New Accounting Standards

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

and requires a liability to be recorded if the fair value of the obligation can be reasonably estimated. The types of asset retirement obligations that are covered by FIN 47 are those for which an entity has a legal obligation to perform an asset retirement activity; however the timing and/or method of settling the obligation are conditional on a future event that may or may not be within the control of the entity. FIN 47 is effective for fiscal years ending after December 15, 2005. This new standard has no impact on the financial statements of the Trust.

Distributable Income Per Unit

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

Federal Income Taxes

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

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 September 2004, the Trust received a refund from the State of Oklahoma in the amount of $510,271. This refund represented taxes that were withheld from the proceeds of production from the Royalty Properties and remitted to the State of Oklahoma by purchasers. Income taxes are not payable by the Trust, but are the responsibility of the individual Unit holders. Therefore the State of Oklahoma refunded the withheld taxes, and the refund was included as royalty income in the Trust’s October 2004 distribution.

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

4. Other Payables

Other payables consist of the following:


December 31,		2005		2004

Royalty receipts in suspense pending verification of ownership interest or title		$	176,176	$	140,432

	Total	$	176,176	$	140,432

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, 2005, the Trust declared the following distributions:


Monthly Record Date	Payment Date	Distribution per Unit

January 17, 2006	January 31, 2006	$	.41419
February 15, 2006	February 28, 2006	$	.43431
March 15, 2006	March 29, 2006	$	.28242

Proxy Solicitation

Despite the similarity of the name of Sabine Production Partners, LP (“SPP”), it is not an entity that is affiliated with Sabine Royalty Trust (“SRT” or the “Trust”).

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:


	2005		2004		2003

Trustee’s fee (Bank of America, N.A.)	$	297,187	$	291,480	$	288,221
Escrow agent’s fee (Bank of America, N.A.)		891,548		874,438		864,652
Professional fees		377,214		264,216		182,745
Unit holders’ services fees		344,259		244,970		267,427
Other		179,339		126,720		146,108

Total General and Administrative Expenses		2,089,547		1,801,824		1,749,153

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, 2005 and 2004 (in thousands, except per Unit amounts):


Calender	Royalty		Distributable		Distributable
Quarter	Income		Income		Income per Unit

2005
First Quarter	$	12,354	$	11,718	$	0.80
Second Quarter		11,769		11,264		0.78
Third Quarter		13,695		13,303		0.91
Fourth Quarter		16,778		16,396		1.12

	$	54,595	$	52,681	$	3.61

2004
First Quarter	$	9,709	$	9,233	$	0.63
Second Quarter		10,376		9,889		0.68
Third Quarter		11,984		11,612		0.80
Fourth Quarter		10,270		9,854		0.67

	$	42,339	$	40,588	$	2.78

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 Statement of Financial Accounting Standards No. 69 (“SFAS 69”) and the guidelines established by the Securities and Exchange Commission. Certain information required by SFAS 69 is not presented because that information is not applicable to the Trust due to its passive nature.

Oil and gas reserve quantities (all located in the United States) are estimates based on information available at the time of their preparation. Such estimates are subject to change as additional information becomes available. Reserves actually recovered, and the timing of the production of those reserves, may

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

differ substantially from original estimates. The following schedule presents changes in the Trust’s total proved reserves (in thousands):


		Oil			Gas
		(Barrels)			(Mcf)

January 1, 2003			5,085			36,332
	Revisions of previous statements		880			6,546
	Production		(481	)		(5,929	)

December 31, 2003			5,484			36,949
	Revisions of previous statements		664			5,586
	Production		(463	)		(4,926	)

December 31, 2004			5,685			37,609
	Revisions of previous statements		1,152			3,359
	Production		(569	)		(4,566	)

December 31, 2005			6,268			36,402

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, 2003		5,067		36,239
	December 31, 2003		5,454		36,878
	December 31, 2004		5,642		37,550
	December 31, 2005		6,197		36,172

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 current (at year end) oil and gas prices ($53.65 per bbl and $8.64 per Mcf, respectively) 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. 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,	2005			2004			2003

Future net cash inflows	$	566,077		$	382,852		$	324,013
Discount of future net cash flows @ 10%		(278,300	)		(188,623	)		(155,206	)

Standardized measure of discounted future net cash inflows	$	287,777		$	194,229		$	168,807

SABINE ROYALTY TRUST

NOTES TO FINANCIAL STATEMENTS — (Continued)

The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2005, 2004 and 2003 is as follows (in thousands):


	2005			2004			2003

Standardized measure of discounted future net cash flows, January 1,	$	194,229		$	168,807		$	138,455
Royalty income, net of severance and ad valorem taxes		(54,595	)		(42,339	)		(38,762	)
Changes in prices, net of related costs		85,699			27,440			23,279
Revisions of previous estimates and other		43,021			23,440			31,989
Accretion of discount		19,423			16,881			13,846

Standardized measure of discounted future net cash flows, December 31,	$	287,777		$	194,229		$	168,807

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 March 6, 2006, the NYMEX posted oil price was approximately $62.41 per barrel, which compared to the posted price of $60.32 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 March 6, 2006, the NYMEX posted gas price was $6.49 per million British thermal units. The use of such price, as compared to the posted price of $10.06 per million British thermal units, used to calculate the future net revenue of the Trust’s proved developed reserves would result in a smaller standardized measure of discounted future net cash flows for gas.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To 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, 2005, 2004 and 2003. 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, 2005, 2004 and 2003, on the basis of accounting described in Note 3.

/s/ PRICEWATERHOUSECOOPERS LLP

PricewaterhouseCoopers LLP

Dallas, Texas

March 10, 2006

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, 2005


	2005		2004		2003

Trustee’s fee	$	297,187	$	291,480	$	288,221
Escrow agent’s fee		891,548		874,438		864,652

Total fees and expenses		1,188,735		1,165,918		1,152,873

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 forgo bonuses earned of $61,261, $34,082 and $22,118 in 2005, 2004 and 2003, 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.


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 2004 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 and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting — modified cash basis (“internal control over financial reporting”) based on the criteria established in Internal Control — Integrated Framework 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, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2004. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2004 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.

Report of Independent Registered Public Accounting Firm

UNIT HOLDERS OF SABINE ROYALTY TRUST AND BANK OF AMERICA, N.A., TRUSTEE

We have audited the Trustee’s assessment, included in the accompanying trustee’s report on internal control over financial reporting, that Sabine Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting — modified cash basis (“internal control over financial reporting”) and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

The 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 3 to the Trust’s financial statements. The 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, the Trustee’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control — Integrated Framework 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, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005, 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 10, 2006 expressed an unqualified opinion on those financial statements.

DELOITTE & TOUCHE LLP

Dallas, Texas

March 10, 2006


Item 9B.	*Other Information.*

None.

PART III


Item 10.	*Directors and Executive Officers of the Registrant.*

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, Bank of America, N.A., 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.*

(a) Security Ownership of Certain Beneficial Owners. As of March 6, 2006 there were no Unit holders known to the Trustee to be beneficial owners of more that 5% of the outstanding 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 16, 2006 an aggregate of 202,089 Units in various fiduciary capacities, and it had shared voting and investment power with respect to 23,359 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.


Item 13.	*Certain Relationships and Related Transactions.*

Not applicable.


Item 14.	*Principal Accounting Fees and Services.*

Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2005 and 2004 are:


	2005		2004

Audit fees	$	163,825	$	84,000
Audit-related fees	$	0	$	0
Tax fees	$	44,550	$	22,795
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, 2005 and 2004

	Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2005

	Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2005

	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 15, 2006 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
(99)		— Report dated February 10, 2006 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2005.


	*	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.

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 15, 2006

(The Registrant has no directors or executive officers.)

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 15, 2006 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
	(99)		— Report dated February 10, 2006 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2005.


	*	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.


	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 annual 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 annual report;

	3. Based on my knowledge, the financial statements, and other financial information included in this annual 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 annual 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 annual 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 annual report my conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this annual report based on such evaluation; and

	d) disclosed in this annual 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


	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.


	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.



	Ron Hooper
	Senior Vice President and Trust Administrator
	Bank of America, N.A.


	(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.