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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 an accelerated filer (as defined in Rule 12b-2 of the Securities and Exchange Act of 1934). Yes x No o

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 $389 million.

At March 5, 2004, there were 14,579,345 units of beneficial interest outstanding.

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 created an Internet website in early 2003, 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 Exchange Act 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 interest, 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.

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.

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 2003 were $1,749,153 of which, pursuant to the terms of the Trust Agreement, $288,221 was paid to Bank of America, as Trustee, and $864,652 was paid to Bank of America, as escrow agent.

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.

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”.

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”. Legislation that was introduced in the 2003 Texas legislature to repeal the “rule against perpetuities” failed to pass. The Texas legislature does not meet again in regular session until 2005, and it is not known whether a proposal to repeal the “rule against perpetuities” will be introduced at that time. Thus far, this issue has not been brought up in any special session in 2004.

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.

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.

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 5, 2004, 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.

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.

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.

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.

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.

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.

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 5 of the 6 states 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.

Pursuant to the terms of the escrow agreements 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 agents and are paid to and received by the Trust only on the next Monthly Record Date. The escrow agents have agreed to endeavor to assure that they incur and pay 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 arrangements are recognized for federal income tax purposes and that the Trustee and the escrow agents are 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 and the escrow agents 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 arrangements are 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. 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 has been expressed by legal counsel with respect to the tax consequences of the escrow arrangements. In the absence of the escrow arrangements, the Unit holders would be deemed to receive or accrue income from production from the Royalty Properties (and interest income) 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 Trust. If the escrow arrangements are 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 arrangements as effective for tax purposes and furnishes tax information to Unit holders on that basis.

The Service might take the position that the escrow arrangements 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 resulting 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, 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 arrangements are not recognized, a mismatching of such income and deduction 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 agreements 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.

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.

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. Income of the Units attributable to interests located in Louisiana will, subject to applicable minimum filing requirements, be subject to Louisiana income tax, and the Trustee is required to file with Louisiana a return reflecting the income of the Trust attributable to mineral interests located in Louisiana. Additionally, 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. 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), 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.

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.

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.

The Trust’s average per barrel oil price increased from $21.82 in 2002 to $26.17 in 2003. The Trustee believes that the international instability coupled with a more favorable economic outlook led to the increase in the price of oil. The price of domestic oil in major part is set by OPEC. Consequently, crude oil market prices are not predictable or completely subject to normal free market forces.

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 2003 on natural gas volumes sold of $4.39 per Mcf represented an increase from the $2.70 per Mcf received in 2002, due largely to international instability and cooler weather in the fall and early winter.

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.

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, 2003.

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 an accurate count of the number of wells located on the Royalty Properties and cannot readily obtain such information.

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.

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, 2004 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. 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.

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, 2004, 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 2004 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 38 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, 2003. 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, 2004. In the preparation of this study, data available from wells drilled on the appraised properties through October 31, 2003, were used in estimating gross ultimate recovery. When applicable, gross production estimated to January 1, 2004, was deducted from gross ultimate recovery to arrive at the estimates of gross reserves as of

January 1, 2004. In some fields, this required that the production rates be estimated for up to 4 months, since production data were available only through August 2003.

Estimated net proved reserves, as of January 1, 2004, attributable to the Trust from the properties appraised are summarized in thousands of barrels (Mbbl) or millions of cubic feet (MMcf) as follows:

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, 2004. 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, 2004, based on receipts by the Trust in December 2003. The assumptions used for estimating future prices and expenses are as follows:

Oil, condensate, natural gas liquids, and natural gas prices, based on receipts by the Trust in December 2003, were furnished by Bank of America. These prices were adjusted to the NYMEX posted prices for oil of $32.55 per barrel and for gas of $5.83 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 $29.03 per barrel and $5.28 per thousand cubic feet.

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, 2004, based on the aforementioned assumptions concerning prices and expenses is summarized as follows, expressed in thousands of dollars (M$):

The present worth, at a discount rate of 10 percent, of future net revenue, as of January 1, 2004, is estimated to be M$168,807.

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 38 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 and escrow agents’ 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 2004 will be approximately $1,900,000.

The present worth of future net revenue of the Trust’s proved developed reserves increased from $138,455,065 at January 1, 2003 to $168,807,194 at January 1, 2004. This increase resulted primarily from the gas prices used in the calculation of such amount, from $4.13 per Mcf of gas at January 1, 2003 to $5.28 per Mcf of gas at January 1, 2004. This increase in the price of gas was offset somewhat by a decrease in the oil prices used to calculate the present net worth of future net revenue from $29.20 per barrel of oil at January 1, 2003 to $29.03 per barrel of oil at January 1, 2004.

Subsequent to year end, the price of both oil and gas continued to fluctuate, giving rise to a correlating adjustment of the respective standardized measure of discounted future net cash flows. As of February 17, 2004, published oil prices were approximately $35.18 per barrel, which compared to $29.03 per barrel, used to calculate the above information, would result in a larger standardized measure of discounted future net cash flows for oil. As of February 17, 2004, published gas prices were approximately $5.66 per Mcf. The use of such price, as compared to $5.28 per Mcf, which was used to calculate the above information, would result in a larger standardized measure of discounted future net cash flows for gas.

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

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 5. Market for Registrant’s Common Equity and Related Stockholder Matters.

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.

At March 5, 2004, there were 14,579,345 Units outstanding and approximately 2,435 Unit holders of record.

The Trust did not repurchase any Units during the period covered by this report.

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

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.

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 Royalties, 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 March, 2002, the Trust received a cash settlement of approximately $828,000 relating to the Multidistrict Litigation Docket no. 1206 (“MDL 1206”), a class action lawsuit, filed against numerous companies (the “Defendants”) that produce, sell and/or purchase domestic crude oil. These claims were based upon methods used by the Defendants to calculate payments to royalty owners. The complaint alleged that, as a result of the price-fixing conspiracy among the Defendants, their payments to class members have been placed upon per barrel values that were less than competitive market values. The MDL 1206 complaint stated that the alleged price-fixing conspiracy violated federal antitrust law. It also alleged certain state law violations, including claims for breach of contract. This settlement was included in the April 2002 distribution along with monies received in the normal course of business. In August, 2003, the Trust received approximately $312,000 from the Oklahoma Tax Commission, a refund of 2002 income tax paid, which was included in the September, 2003 distribution.

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 2002 and 2003.

Net royalty income during 2003 increased approximately $10,627,000, or 37.8 percent, compared to 2002 net royalty income, which had decreased approximately $16,088,000, or 36.4 percent, from 2003 net royalty income.

Revenues generated by sales of oil and gas increased in 2003 from 2002 as a result of higher gas and oil prices as well as higher oil volumes. These increases were tempered by a decrease in natural gas volumes. Gas volumes decreased from 6,691,473 thousand cubic feet (“Mcf”) in 2002 to 6,532,013 Mcf in 2003 after decreasing from 7,701,397 Mcf in 2001. The average price per Mcf of gas received by the Trust increased from $2.70 per Mcf in 2002 to $4.39 per Mcf in 2003, after decreasing from $4.53 per Mcf in 2001. The Trustee believes that normal market forces, international instability, and the cooler weather in late fall and early winter resulted in the higher gas prices.

Oil volumes sold increased to 557,087 barrels in 2003 from 537,534 barrels in 2002, having decreased from 573,354 barrels in 2001. The effect of this volume increase was furthered by an increase in the average price per barrel received by the Trust to $26.17 in 2003 from $21.82 in 2002, which was a decrease from $23.88 in 2001. International instability along with cooler weather in the late fall and early winter led to the increase in price for 2003.

Interest income increased to $47,000 in 2003 from $43,000 in 2002, which decreased from $205,000 in 2001. Changes in interest income are the result of changes in interest rates and funds available for investment. General and administrative expenses increased to $1,749,000 in 2003 compared to $1,638,000 in 2002 due to increases in professional fees and auditing fees of approximately $73,000 and $20,000, respectively. General and administrative expenses increased to $1,638,000 in 2002 compared to $1,622,000 in 2001 due to increases in the escrow agent fees and trustee fees of approximately $40,000 and $12,000, respectively. These increases were somewhat offset by a decrease in professional fees of approximately $33,000.

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.

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 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.

Revenues from Royalty Interests are recognized in the period in which amounts are received by the Trust. Royalty income received by the Trust 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.

Independent petroleum engineers estimate the net proved reserves attributable to the Royalty Interest. 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.

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, 2003.

SFAS No. 148, “Accounting for Stock-Based Compensation — Transition and Disclosure, an amendment of FASB Statement No. 123,” was issued in December 2002 and provides new transition methods if an entity adopts the fair value based method of valuing stock-based compensation suggested in SFAS No. 123 “Accounting for Stock-Based Compensation,” as well as requiring additional disclosures in interim and annual financial statements. The Trust has no options or other stock-based instruments and accordingly, the impact of this new Standard was not material to the financial statements of the Trust.

SFAS No. 149, “Accounting for Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133” was issued in April 2003 and is effective for contracts entered into after June 20, 2003. The statement amends and clarifies financial accounting and reporting for derivative instruments, including certain derivative instruments embedded in other contracts. The Trust has no derivative instruments and accordingly, the impact of this new standard will not be material to the financial statements of the Trust.

SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity” was issued in May 2003, and is effective for fiscal quarters beginning after June 15, 2003. The Trust has no Financial Instruments and accordingly, the impact of this new standard will not be material to the financial statements of the Trust.

FASB interpretation (“FIN”) No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” requires disclosures beginning with financial statements ending after December 15, 2002 and requires liability recognition beginning January 1, 2003. The Trust had no such guarantees outstanding as of December 31, 2003.

FIN No. 46, “Consolidation of Variable Interest Entities” was issued in January 2003. This interpretation of Accounting Research Bulletin No. 51, “Consolidated Financial Statements,” applies immediately to variable interest entities created after January 31, 2003 and applies to the first period beginning after June 15, 2003 to entities acquired before February 1, 2003. This FIN does not affect the Trust as it has no unconsolidated subsidiaries accounted for under the equity method of accounting.

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 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.

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 2001 and 2003. The following table presents the weighted average prices received per year by the Trust:

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) and the recoverability of reserves, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets.

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 Unitholders 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 Unitholders 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.

We have audited the accompanying statements of assets, liabilities and trust corpus of Sabine Royalty Trust (the “Trust”) as of December 31, 2003 and 2002, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the United States of America. 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 statements were prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America.

In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the Trust at December 31, 2003 and 2002, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2003, on the basis of accounting described in Note 2.

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 “Royalties”).

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 Royalties 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 Royalties, and Pacific (USA)’s ownership of such rights was not affected by the sale.

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 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 Royalties 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 Royalties located in five of the six states 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 Royalties 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 Royalties 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.

Pursuant to the terms of the escrow agreements and the conveyances of the properties by Sabine, the proceeds of production from the Royalties for each calendar month, and interest thereon, are collected by the escrow agents and are paid to and received by the Trust only on the next monthly record date. The escrow agents have agreed to endeavor to assure that they incur and pay 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 agreements are recognized for Federal income tax purposes and that the Trustee and the escrow agents are 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 agents 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. 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.


	•	Royalty income, net of severance and ad valorem taxes, and interest income are recognized in the month in which amounts are received by the Trust (see Note 1).

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

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

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

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


	•	Royalty income is recognized in the month received rather than in the month of production.

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

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


	•	Reserves may be established for contingencies that would not be recorded under accounting principles generally accepted in the United States of America.

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.

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.

Basic earnings per Unit is computed by dividing net income by the weighted average Units outstanding. Earnings per Unit assuming dilution is computed by dividing net income by the weighted

average number of Units and equivalent Units outstanding. The Trust had no equivalent Units outstanding for any period presented. Basic and assuming dilution distributable income per Unit are the same.

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, which is discussed above in Note 1.

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 March, 2002, the Trust received a cash settlement of approximately $828,000 relating to the Multidistrict Litigation Docket no. 1206 (“MDL 1206”), a class action lawsuit, filed against numerous companies (the “Defendants”) that produce, sell and/or purchase domestic crude oil. These claims were based upon methods used by the Defendants to calculate payments to royalty owners. The complaint alleged that, as a result of the price-fixing conspiracy among the Defendants, their payments to class members have been placed upon per-barrel values that were less than competitive market values. The MDL 1206 complaint stated that the alleged price-fixing conspiracy violated federal antitrust law. It also alleged certain state-law violations, including claims for breach of contract. This settlement was included in the April 2002 distribution along with monies received in the normal course of business. In August, 2003, the Trust received approximately $312,000 from the Oklahoma Tax Commission, a refund of 2002 income tax paid, which was included in the September, 2003 distribution.

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.

Subsequent to December 31, 2003, the Trust declared the following distributions:

Fees and expenses for the years ended December 31, associated with the Trustee’s services for the Trust pursuant to the Trust Agreement, were as follows:

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, 2003 and 2002 (in thousands, except per Unit amounts):

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 and the guidelines established by the Securities and Exchange Commission.

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

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

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

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 ($29.03 per bbl and $5.28 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.

The change in the standardized measure of discounted future net cash flows for the years ended December 31, 2003, 2002 and 2001 is as follows (in thousands):

Subsequent to year end, both the price of oil and gas continued to fluctuate, giving rise to a correlating adjustment of the respective standardized measure of discounted future net cash flows. As of February 17, 2004, published oil prices were approximately $35.18 per barrel, which compared to $29.03 per barrel, used to calculate the above information, would result in a larger standardized measure of discounted future net cash flows for oil. As of February 17, 2004, published gas prices were approximately $5.66 per Mcf. The use of such price, as compared to $5.28 per Mcf, which was used to calculate the above information, would result in a larger standardized measure of discounted future net cash flows for gas.

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, 2003, 2002 and 2001. 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 auditing standards generally accepted in the United States of America. 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, 2003, 2002 and 2001, on the basis of accounting described in Note 3.

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 $22,118, $38,308 and $56,041 in 2003, 2002 and 2001, 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 generally accepted accounting principles. 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.

As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Exchange Act Rules 13a-15 and 15d-15. Based upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely alerting the Trustee to material information relating to the Trust required to be included in the Trust’s periodic filings with the Securities and Exchange Commission. There has not been any change in the Trust’s internal control over financial reporting during the period covered by this report that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

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 Exchange Act.

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.

(a) Security Ownership of Certain Beneficial Owners. As of February 18, 2004 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 March 1, 2004 an aggregate of 218,314 Units in various fiduciary capacities, and it had shared voting and investment power with respect to 28,584 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.

Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2003 and 2002 are:

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.


	Independent Auditors’ report

	Statements of Assets, Liabilities and Trust Corpus at December 31, 2003 and 2002

	Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2003

	Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2003

	Notes to Financial Statements

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.


	*	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.

(b) Reports on Form 8-K. The Trust did not file any reports on Form 8-K during the last quarter of the period covered by this report; however, the Trust furnished the following reports on Form 8-K during the same time period:


	On October 7, 2003, the Trust furnished a report on Form 8-K dated October 3, 2003, to announce its monthly cash distribution to Unit holders of record on October 15, 2003.

	On November 5, 2003, the Trust furnished a report on Form 8-K dated November 4, 2003, to announce its monthly cash distribution to Unit holders of record on November 17, 2003.

	On December 8, 2003, the Trust furnished a report on Form 8-K dated December 3, 2003, to announce its monthly cash distribution to Unit holders of record on December 15, 2003.

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.


	*	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.


(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, 2003

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

		For the transition period from to


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)


		Name of Each Exchange
Title of Each Class		on Which Registered

Units of Beneficial Interest		New York Stock Exchange


		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		9
Item 2.	Properties		10
	Title		11
	Reserves		11
Item 3.	Legal Proceedings		16
Item 4.	Submission of Matters to a Vote of Security Holders		16
PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters		17
Item 6.	Selected Financial Data		17
Item 7.	Trustee’s Discussion and Analysis of Financial Condition and Results of Operations		17
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		21
Item 8.	Financial Statements and Supplementary Data		22
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		34
Item 9A.	Controls and Procedures		34
PART III
Item 10.	Directors and Executive Officers of the Registrant		34
Item 11.	Executive Compensation		34
Item 12.	Security Ownership of Certain Beneficial Owners and Management		34
Item 13.	Certain Relationships and Related Transactions		34
Item 14.	Principal Accounting Fees and Services		35
PART IV
Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K		35
Consent of DeGolyer and MacNaughton
Rule 13a-14(a)(15d-14(a)) Certification
Certification Pursuant to Section 906
Report dated February 2, 2004



		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

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		Proved Developed				Proved Undeveloped
		Reserves				Reserves

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

Florida			119		19		0		0
Louisiana			77		811		0		0
Mississippi			80		2,653		15		64
New Mexico			414		3,278		0		0
Oklahoma			430		10,000		0		0
Texas			4,334		20,117		15		7

	Total		5,454		36,878		30		71


	*Oil, Condensate, Natural Gas Liquids, and Natural Gas Prices*


Year	Future Net
Ending	Revenue
December 31	(M$)

2004		35,288
2005		30,419
2006		26,707

Subtotal		92,414
Remaining		231,599

Total		324,013



	Sales Price
					Distributions
	High		Low		Per Unit

2003
First Quarter	$	24.75	$	19.58	$	0.45499
Second Quarter		27.80		20.52		0.80739
Third Quarter		28.25		25.48		0.69668
Fourth Quarter		29.40		25.81		0.56350
2002
First Quarter	$	24.45	$	21.10	$	0.50792
Second Quarter		26.14		20.35		0.45452
Third Quarter		25.05		15.00		0.54615
Fourth Quarter		25.40		21.50		0.37024


Years Ended December 31	2003		2002		2001		2000		1999

Royalty Income	$	38,761,739	$	28,134,458	$	44,222,701	$	34,407,684	$	23,042,432
Distributable Income		37,060,003		26,539,751		42,805,378		33,122,044		21,725,813
Distributable Income per Unit		2.54		1.82		2.94		2.27		1.49
Total Assets at Year End		5,555,045		5,391,280		5,855,378		5,239,610		5,474,918
Distributions per Unit		2.52		1.88		2.86		2.27		1.41


			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


	Oil		Gas
	Per BBL		Per Mcf

2003		26.17		4.39
2002		21.82		2.70
2001		23.88		4.53



	December 31,

	2003		2002

Assets
Cash and short-term investments	$	4,247,094	$	3,898,379
Royalty interests in oil and gas properties less accumulated amortization of $21,087,234 (2003) and $20,902,284 (2002)		1,307,951		1,492,901

Total	$	5,555,045	$	5,391,280

Liabilities and Trust Corpus
Trust expenses payable	$	427,982	$	408,121
Other payables (Note 4)		426,070		379,940

Total liabilities		854,052		788,061
Trust corpus (14,579,345 units of beneficial interest authorized and outstanding)		4,700,993		4,603,219

Total	$	5,555,045	$	5,391,280



	Year Ended December 31,

	2003		2002		2001

Royalty income	$	38,761,739	$	28,134,458	$	44,222,701
Interest income		47,417		43,337		205,134

Total		38,809,156		28,177,795		44,427,835
General and administrative expenses (Note 6)		1,749,153		1,638,044		1,622,457

Distributable income	$	37,060,003	$	26,539,751	$	42,805,378

Distributable income per unit (Basic and Assuming Dilution) (14,579,345 units) (Note 1)	$	2.54	$	1.82	$	2.94

Distributions per unit (Note 3)	$	2.52	$	1.88	$	2.86


Monthly Record Date	Payment Date	Distribution per Unit

January 15, 2004	January 29, 2004	$	.23520
February 17, 2004	February 27, 2004	$	.18008
March 15, 2004	March 29, 2004	$	.18951


	*Expenses*


Calendar		Royalty		Distributable		Distributable
Quarter		Income		Income		Income per Unit

2003
	First Quarter	$	8,562	$	8,050	$	0.55
	Second Quarter		11,552		11,071		0.76
	Third Quarter		9,742		9,381		0.64
	Fourth Quarter		8,906		8,558		0.59

		$	38,762	$	37,060	$	2.54

2002
	First Quarter	$	6,971	$	6,562	$	0.45
	Second Quarter		6,092		5,653		0.39
	Third Quarter		7,819		7,413		0.51
	Fourth Quarter		7,252		6,912		0.47

		$	28,134	$	26,540	$	1.82


		Oil			Gas
		(Barrels)			(Mcf)

January 1, 2001			5,552			38,476
	Revisions of previous statements		396			4,962
	Production		(518	)		(5,949	)

December 31, 2001			5,430			37,489
	Revisions of previous statements		181			4,457
	Production		(526	)		(5,614	)

December 31, 2002			5,085			36,332
	Revisions of previous statements		880			6,546
	Production		(481	)		(5,929	)

December 31, 2003			5,484			36,949


Item 9A.	*Controls and Procedures.*


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


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


Item 12.	*Security Ownership of Certain Beneficial Owners and Management.*


Item 13.	*Certain Relationships and Related Transactions.*


	2003		2002

Audit fees	$	83,000	$	79,000
Audit-related fees	$	0	$	0
Tax fees	$	37,589	$	36,464
All other fees	$	0	$	0


Item 15.	*Exhibits, Financial Statement Schedules and Reports on Form 8-K.*



(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 10, 2004 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
(99)		— Report dated February 2, 2004 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2003.


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 10, 2004 and submitted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
	(99)		— Report dated February 2, 2004 of the Trustee containing interim tax information for each of the 12 months in the year ending December 31, 2003.