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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 þ 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. o

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes þ No o

State the aggregate market value of the Units of Beneficial Interest held by non-affiliates of the Registrant as of June 30, 2003: $836,627,888.

At March 12, 2004, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.

“Units of Beneficial Interest” at page 1; “Description of the Properties” at page 4; “Trustee’s Discussion and Analysis” at pages 5-10; and “Statements of Assets, Liabilities and Trust Corpus,” “Statements of Distributable Income,” “Statements of Changes in Trust Corpus,” “Notes to Financial Statements,” and “Independent Auditors’ Report” at page 12 et seq., in registrant’s Annual Report to Unit Holders for the year ended December 31, 2003 are incorporated herein by reference for Item 5 (Market for Registrant’s Units, Related Security Holder Matters and Issuer Purchases of Units), Item 7 (Trustee’s Discussion and Analysis of Financial Condition and Results of Operation) and Item 8 (Financial Statements and Supplementary Data) of Part II of this Report.

Certain information included in this Annual Report on Form 10-K contains, and other materials filed or to be filed by the San Juan Basin Royalty Trust (the “Trust”) with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices and the results thereof, and regulatory matters. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements reflect Burlington Resources Oil & Gas Company LP’s (“BROG”), the working interest owner’s, current view with respect to future events; are based on an assessment of, and are subject to, a variety of factors deemed relevant by TexasBank, the Trustee of the Trust, and BROG and involve risks and uncertainties. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated.

The Trust is an express trust created under the laws of the state of Texas by the San Juan Basin Royalty Trust Indenture (the “Original Indenture”) entered into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and the Fort Worth National Bank. Effective as of September 30, 2002, the Original Indenture was amended and restated (the Original Indenture, as amended and restated, the “Trust Indenture”). The Trustee of the Trust is TexasBank. The principal office of the Trust is located at 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116, Attention: Trust Department (telephone number (866) 809-4553). The Trust maintains a website at www.sjbrt.com. The Trust makes available (free of charge) its annual, quarterly and current reports (and any amendments thereto) filed with the Securities and Exchange Commission (the “SEC”) on its website as soon as reasonably practicable after electronically filing or furnishing such material with or to the SEC.

On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company’s conveyance of a 75% net overriding royalty interest (equivalent to a net profits interest) to the Trust for the benefit of the stockholders of Southland Royalty of record at the close of business on the date of the conveyance (the “Royalty”) carved out of that company’s oil and gas leasehold and royalty interests in properties located in the San Juan Basin of northwestern New Mexico (the “Underlying Properties”). Pursuant to the Net Overriding Royalty Conveyance (the “Conveyance”) the Royalty was transferred to the Trust on November 3, 1980, effective as to production from and after November 1, 1980 at 7:00 A.M.

The Royalty was carved out of and now burdens the Underlying Properties as more particularly described under “Item 2. Properties” herein.

The Royalty constitutes the principal asset of the Trust and the beneficial interests in the Royalty are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980 received one Unit for each share of the common stock of Southland Royalty then held. Holders of Units are referred to herein as “Unit Holders.” Subsequent to the conveyance of the Royalty, through a series of assignments and mergers, Southland Royalty’s successor became BROG.

The function of the Trustee is to collect the income attributable to the Royalty, to pay all expenses and charges of the Trust, and then distribute the remaining available income to the Unit Holders. The Trust is not empowered to carry on any business activity and has no employees, all administrative functions being performed by the Trustee.

The term “net proceeds,” as used in the Conveyance, means the excess of “gross proceeds” received by BROG during a particular period over “production costs” for such period. “Gross proceeds” means the amount received by BROG (or any subsequent owner of the Underlying Properties) from the sale of the production attributable to the Underlying Properties subject to certain adjustments. “Production costs” generally means costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes and operating charges. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to the Underlying Properties or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such amount, plus interest, at a rate specified in the Conveyance.

Compliance with state and federal environmental protection laws could reduce the income attributable to the Royalty received by the Trust. Costs of complying with such laws and regulations impact the production costs incurred by BROG in operating the Underlying Properties and may also affect capital expenditures by BROG. The Trust has no information regarding any estimated capital expenditures by BROG specifically allocable to environmental control facilities in the current or succeeding fiscal years.

Certain of the Underlying Properties are operated by BROG with the obligation to conduct its operations in accordance with reasonable and prudent business judgment and good oil and gas field practices. As operator, BROG has the right to abandon any well when, in its opinion, such well ceases to produce or is not capable of producing oil and gas in paying quantities. BROG also is responsible, subject to the terms of an agreement with the Trust, for marketing the production from such properties, either under existing sales contracts or under future arrangements at the best prices and on the best terms it shall deem reasonably obtainable in the circumstances. BROG also has the obligation to maintain books and records sufficient to determine the amounts payable to the Trustee.

Proceeds from production in the first month are generally received by BROG in the second month, the net proceeds attributable to the Royalty are paid by BROG to the Trustee in the third month and distribution by the Trustee to the Unit Holders is made in the fourth month. Unit Holders of record as of the last business day of each month (the “monthly record date”) will be entitled to receive the calculated monthly distribution amount for such month on or before ten business days after the monthly record date. The amount of each monthly distribution will generally be determined and announced ten days before the monthly record date. The aggregate monthly distribution amount is the excess of (i) the net proceeds attributable to the Royalty paid to the Trustee, 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 net increase in cash reserves for contingent liabilities.

Cash being held by the Trustee as a reserve for liabilities or contingencies (which reserves may be established by the Trustee in its discretion) or pending distribution is placed, in the Trustee’s discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any agency thereof, repurchase agreements secured by obligations issued by the United States or any agency thereof, certificates of deposit of banks having capital, surplus and undivided profits in excess of $50,000,000, or money market funds that have been rated AAAmg or AAAm by Standard & Poor’s and AA by Moody’s, subject, in each case, to certain other qualifying conditions.

The Underlying Properties are primarily gas producing properties. Normally there is a greater demand for gas in the winter months than during the rest of the year. Otherwise, the income to the Trust attributable to the Royalty is not subject to seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities.

The exploration for and the production of gas and oil is a speculative business. The Trust has no means of ensuring continued income from the Royalty at the present level or otherwise. In addition, fluctuations in prices and supplies of gas and oil and the effect these fluctuations might have on royalty

income to the Trust and on reserves net to the Trust cannot be accurately projected. The Trustee has no information with which to make any projections beyond information on economic conditions which is generally available to the public and thus is unwilling to make any such projections.

BROG has the right to sell its interest in the Underlying Properties and has recommended to the Trust that certain marginal Underlying Properties be sold to third parties. BROG has asked the Trust to join in such proposed sale by conveying the Royalty burdening the properties to be sold. The properties BROG proposes to sell constitute less than 2% of the Underlying Properties. The Trustee is currently evaluating whether its joinder in the sale would be in the best interest of the Unit Holders. The Trust intends to hold a special meeting of Unit Holders in 2004 to consider certain amendments to the Indenture, including an amendment that would allow the Trustee to sell up to a specified percentage of the value of the Royalty each year without obtaining the consent of Unit Holders.

The Royalty conveyed to the Trust was carved out of Southland Royalty’s (now BROG’s) working interests and royalty interests in certain properties situated in the San Juan Basin in northwestern New Mexico (the “Underlying Properties”). See “Item 1. Business” for information on the conveyance of the Royalty to the Trust. References below to “gross” wells and acres are to the interests of all persons owning interests therein, while references to “net” are to the interests of BROG (from which the Royalty was carved) in such wells and acres.

Unless otherwise indicated, the following information in this Item 2 is based upon data and information furnished to the Trustee by BROG.

The Underlying Properties consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico and 3,946 gross (1,170 net) economic wells, including dual completions. Production from conventional gas wells is primarily from the Pictured Cliffs, Mesaverde and Dakota formations. During 1988, Southland Royalty began development of coal seam reserves in the Fruitland Coal formation.

The Royalty conveyed to the Trust is limited to the base of the Dakota formation, which is currently the deepest significant producing formation under acreage affected by the Royalty. Rights to production, if any, from deeper formations are retained by BROG.

In February, 2003, BROG announced an estimated capital budget for the Underlying Properties of approximately $14.1 million. During the year, the estimate was initially increased to $18.0 million, and then ultimately increased to approximately $21.1 million. BROG’s capital plan for the Underlying Properties for 2003 estimated 351 projects, including the drilling of 38 new wells to be operated by BROG and 26 wells to be operated by third parties. In 2003, BROG actually participated in 509 projects, including 58 new wells operated by BROG and 10 wells operated by third parties. BROG reported that the swings in the budget estimates related in large part to whether and when BROG was successful in obtaining the necessary governmental and landowner approvals to drill on a well-by-well basis.

The aggregate capital expenditures reported by BROG in calculating net proceeds payable to the Trust for 2003 include approximately $6.5 million attributable to the capital budgets for prior years. This occurs because projects within a given year’s budget may extend into subsequent years, with capital expenditures attributable to those projects used in calculating distributable income to the Trust in those subsequent years. Further, BROG’s accounting period for capital expenditures runs through November 30 of each calendar year, such that capital expenditures incurred in December of each year are actually accounted for as part of the following year’s capital expenditures. In addition, with respect to wells not operated by BROG, BROG’s share of capital expenditures may not actually be paid by it until the year or years after those expenses were incurred by the operator. Capital expenditures of approximately

$14.6 million for 2003 budgeted projects were used in calculating net proceeds payable to the Trust in calendar year 2003, and approximately $5.3 million in capital expenditures were used in calculating net proceeds payable to the Trust for January and February 2004. Therefore, an additional approximately $1.2 million in capital expenditures for 2003 projects remains to be spent.

During 2003, in calculating the net proceeds to the Trust, BROG deducted approximately $20.6 million of capital expenditures for projects, including drilling and completion of 44 gross (15.36 net) conventional wells, recompletion of two gross (.07 net) conventional wells, three gross (.94 net) miscellaneous capital projects, 29 gross (21.55 net) restimulations, 49 gross (3.22 net) conventional payadds, 53 gross (16.98 net) coal seam wells, nine gross (1.6 net) coal seam recompletions, two gross (.92 net) coal seam recavitations, one gross (.04 net) coal seam restimulation, and two gross (.88 net) miscellaneous coal seam capital projects and facilities maintenance. There were 32 gross (7.0 net) new conventional wells, recompletion of 15 gross (3.72 net) conventional wells, 22 gross (9.11 net) conventional well restimulations, 14 gross (3.65 net) conventional payadds, 54 gross (14.43 net) coal seam wells, six gross (1.62 net) coal seam recompletions, one gross (.002 net) recavitation, and six gross (.20 net) miscellaneous coal seam capital projects in progress as of December 31, 2003. A payadd is the completion of an additional productive interval in an existing completed zone in a well.

During 2002, in calculating the net proceeds to the Trust, BROG deducted approximately $21.5 million of capital expenditures for projects, including drilling and completion of 98 gross (30.05 net) conventional wells, recompletion of 36 gross (14.44 net) conventional wells, 13 gross (2.21 net) miscellaneous capital projects, one gross (.82 net) restimulation, one gross (.05 net) payadd, 16 gross (5.42 net) coal seam wells, 11 gross (1.45 net) miscellaneous coal seam capital projects, 14 gross (5.77 net) coal seam recompletions, five gross (.98 net) coal seam recavitations, and three gross (.01 net) coal seam restimulations and facilities maintenance. There were 61 gross (24.49 net) new conventional wells, 20 gross (4.69 net) conventional well recompletions, 65 gross (19.82 net) miscellaneous conventional capital projects, four gross (1.41 net) coal seam wells, two gross (.99 net) coal seam recompletions, and five gross (1.72 net) miscellaneous coal seam capital projects in progress as of December 31, 2002.

BROG has informed the Trust that its projections for capital expenditures for the Underlying Properties in 2004 is estimated at $18.5 million. Approximately $11.7 million of that budget is allocable to new wells, with approximately 61% of those wells projected to be drilled to formations producing coal seam gas as distinguished from conventional gas, and $6.8 million is to be expended in working over existing wells and in the maintenance and improvement of production facilities. BROG reports that based on its actual capital requirements, its mix of projects and swings in the price of natural gas, the actual capital expenditures for 2004 could range from $15 million to $25 million. BROG anticipates 441 projects, including the drilling of 103 new wells to be operated by BROG and 29 wells to be operated by third parties. Of the new BROG operated wells, 30 are projected to be conventional wells completed to the Pictured Cliffs, Mesaverde, and/or Dakota formations, and the remaining 73 are projected as coal seam gas wells to be completed in the Fruitland Coal formation. A total of 22 of the wells operated by third parties are projected to be conventional wells and the remaining seven are to be coal seam wells.

In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In July 2003, the New Mexico Oil Conservation Division approved 160-acre spacing in the Fruitland Coal formation. BROG informed the Trust that, principally as a result of this approval, its budget for 2004 reflected a continued focus on the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.

BROG indicates its budget for 2004 reflects continued significant development of conventional formations, including infill drilling to the Mesaverde and Dakota formations, development of the Fruitland Coal formation and multiple formation completions. A majority of the new wells for 2004 are projected to be drilled on Underlying Properties in which the fractional working interest included in the Underlying

Properties is relatively low, but many of the recompletions and restimulations are scheduled on properties in which such working interest is relatively high.

The Trust recognizes production during the month in which the related net proceeds attributable to the Royalty are paid to the Trust. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2003 were as follows:

Gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. Gas production from the Underlying Properties totaled 45,202,576 Mcf during 2003.

On September 4, 1996, the Trustee announced a settlement of litigation filed by the Trustee against BROG and Southland Royalty Company. In the settlement, agreement was reached, among other things, regarding marketing arrangements for the sale of those gas, oil and natural gas liquids products from the Underlying Properties going forward as follows:


	(i) BROG agreed that all subsequent contracts for the sale of gas from the Underlying Properties would require the written approval of an independent gas marketing consultant acceptable to the Trust;

	(ii) BROG will continue to market the oil and natural gas liquids from the Underlying Properties but will make payments to the Trust based on actual proceeds from such sales, and BROG will no longer use posted prices as the basis for calculating proceeds to the Trust nor make a deduction for marketing fees associated with sales of oil or natural gas liquids products; and

	(iii) The independent marketer of the gas from the Underlying Properties is entitled to use of BROG’s current gas transportation, gathering, processing and treating agreements with third parties, at least through the remainder of their primary terms.

See Note 5 of Notes to Financial Statements of the Trust’s Annual Report to security holders for the year ended December 31, 2003 for further discussion of this settlement and its impact on the Trust.

BROG has entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties. These contracts provide for (i) the sale of such gas in two packages to Duke Energy and Marketing, L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and (iii) the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing, L.L.C. were assumed by ConocoPhillips Company pursuant to an Assignment and Novation Agreement.

Confidentiality agreements with purchasers of gas produced from the Underlying Properties prohibit public disclosure of certain terms and conditions of gas sales contracts with those entities, including specific pricing terms, gas receipt points, etc. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties.

The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Form 10-K:


	“Estimated future net revenues” are computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. “Estimated future net revenues” are sometimes referred to in this Form 10-K as “estimated future net cash flows.”

	“Present value of estimated future net revenues” is computed using the estimated future net revenues (as defined above) and a discount rate of 10%.

	“Proved reserves” are those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

	“Proved developed reserves” are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

	“Proved undeveloped reserves” are those proved reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

The independent petroleum engineers’ reports as to the proved oil and gas reserves as of December 31, 2001, 2002 and 2003 were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2000 to December 31, 2003 (in thousands):

Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2003, 2002 and 2001 were as follows (in thousands):

Generally, the calculation of oil and gas reserves takes into account a comparison of the value of the oil or gas to the cost of producing those minerals, in an attempt to cause minerals in the ground to be included in reserve estimates only to the extent that the anticipated costs of production will be exceeded by the anticipated sales revenue. Accordingly, an increase in sales price and/or a decrease in production cost can itself result in an increase in estimated reserves and declining prices and/or increasing costs can result in reserves reported at less than the physical volumes actually thought to exist. The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are estimated by applying year-end prices of oil and gas relating to the enterprise’s proved reserves to the year-end quantities of those reserves. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future net cash flows relating to proved oil and gas reserves.

Estimates of proved oil and gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables. Accordingly, under the allocation method used to derive the Trust’s quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and gas reserves and estimated future net revenues.

The 2003, 2002 and 2001 changes in the standardized measure of discounted future net cash flows related to future royalty income from proved reserves discounted at 10% are as follows (in thousands):

Reserve quantities and revenues shown in the tables above for the Royalty were estimated from projections of reserves and revenues attributable to the combined BROG and Trust interests. Reserve quantities attributable to the Royalty were derived from estimates by allocating to the Royalty a portion of the total net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalty are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalty. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur. The future net cash flows were determined without regard to future federal income tax credits available to production from coal seam wells.

December average prices of $4.47 per Mcf of conventional gas, $3.31 per Mcf of coal seam gas and $28.12 per Bbl of oil were used at December 31, 2003, in determining future net revenue. The upward revision in reserve quantities for 2003 as compared to 2002 is due in part to higher oil and gas prices in December 2003 as compared to December 2002.

December average prices of $3.75 per Mcf of conventional gas, $2.80 per Mcf of coal seam gas and $24.88 per Bbl of oil were used at December 31, 2002, in determining future net revenue. The upward revision in reserve quantities for 2002 as compared to 2001 is primarily due to significantly higher oil and gas prices in December 2002 as compared to December 2001.

December average prices of $1.96 per Mcf of conventional gas, $1.42 per Mcf of coal seam gas and $15.79 per Bbl of oil were used at December 31, 2001, in determining future net revenue.

The following presents estimated future net revenues and present value of estimated future net revenues attributable to the Royalty for each of the years ended December 31, 2003, 2002 and 2001 (in thousands, except amounts per Unit):

Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the above estimates. Moreover, the present values shown above should not be considered the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would require the analysis of additional parameters.

Many aspects of the production, pricing and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.

Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that BROG can produce and to limit the number of wells or the locations at which BROG can drill.

The transportation and sale for resale of natural gas in interstate commerce, historically, have been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission (“FERC”) and its predecessor. In the past, the federal government has regulated the prices at which gas could be sold. Congress removed all non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future.

Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several

major regulatory changes have been implemented by Congress and FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.

Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued over the last decade by FERC and Congress will continue.

Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines.

Sales of production from coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits through 2002. Although both houses of Congress are presently considering energy legislation, including provisions to extend or reinstate the Section 29 credit in various ways, whether such provisions will be enacted into law, and if so, the effect thereof on the Trust and the Unit Holders is, at present, unknown. Even though the Section 29 credit does not apply to qualified fuel sold in 2003, a Section 29 credit (at the rate applicable in 2002) may apply to proceeds received in 2003 for qualified fuel sold in 2002 and earlier years for Unit Holders that utilize the cash method of tax accounting. The Internal Revenue Service has issued a private letter ruling to another taxpayer to the effect that cash method taxpayers may claim the Section 29 credit in a later year for sales of qualified fuel in an earlier year where the proceeds from such sales are received in the later year. Because a private letter ruling may be relied on only by the taxpayer who requested the ruling, the Trust applied for a similar ruling. Tax counsel to the Trust has been informed that the Internal Revenue Service intends to issue a Revenue Procedure in the near future allowing a cash basis taxpayer to report the Section 29 credit in either the year the qualifying production is sold or the year the income is received, provided that the taxpayer is consistent in its treatment from year to year and that, accordingly, it will not issue private letter rulings on this question. No assurance can be given, however, whether, or if so when, such a Revenue Procedure will be issued.

To benefit from the credit in 2003, each cash basis Unit Holder must determine from the tax information the Unit Holder received from the Trust, its pro rata share of qualifying production of the Trust sold before January 1, 2003, based upon the number of Units owned during each month of the year, and the amount of available credit per MMbtu for the year, and then apply the tax credit against the Unit Holder’s own income tax liability, but such credit could not reduce the Unit Holder’s regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below his tentative minimum tax. Section 29 also provides that any amount of Section 29 credit disallowed for the tax year solely because of this limitation will increase a taxpayer’s credit for prior year minimum tax liability, which may be carried forward indefinitely as a credit against the taxpayer’s regular tax liability, subject, however, to the limitations described in the preceding sentence. There is no provision for the carryback or carryforward of the Section 29 credit in any other circumstance.

BROG has historically provided to the Trust summary Section 29 tax credit information related to Trust properties. In 1999, the U.S. Court of Appeals for the 10th Circuit upheld the position of the Internal Revenue Service and the Tax Court that nonconventional fuel such as coal seam gas does not

qualify for the Section 29 credit unless the producer has received an appropriate well category determination from the FERC. Substantially all of the wells burdened by the Royalty have received the appropriate well category certification. BROG has informed the Trustee that it will continue to seek certification of any qualified but not certified wells burdened by the Royalty. Unless the Section 29 credit is extended or reinstated in such a way as to include previously drilled wells, however, these actions will not affect the Trust or its Unit Holders in periods after December 31, 2002.

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit Holder. As a result of the Tax Reform Act of 1986, royalty income such as that derived through the Trust will generally be treated as portfolio income and will not reduce passive losses.

The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, environmental protection, occupational safety, resource conservation and equal employment opportunity.

An administrative claim was initiated on March 17, 1997 by the Mineral Management Service of the United States Department of the Interior (the “MMS”) against BROG regarding a gas contract settlement dated March 1, 1990, between BROG and certain other parties thereto. The claim alleged that additional royalties were due on production from federal and Indian leases in the State of New Mexico on properties burdened by the Trust Royalty. On December 3, 2001, BROG settled this claim by paying the Jicarilla Apache Nation the sum of $2,853,974 and the MMS the sum of $1,224,043. MMS also retained certain overpayments by BROG in the amount of $1,127,623 as part of the settlement. Certain properties included in this settlement are burdened by the Royalty. BROG previously offset the entire $2,853,974 Jicarilla component of the settlement against amounts otherwise distributed in payment of the Royalty, and offset $901,776 from the April 2003 distribution to the Trust as the Trust’s 75% portion of the remaining $1,224,043 component of the settlement, slightly reduced by agreement of the parties. BROG has indicated that it does not appear that any of the $1,127,623 in overpayments retained by the MMS is attributable to the Trust.

In June 2000, the Trust and BROG entered into a partial settlement of claims relating to a gas imbalance with respect to production from mineral properties currently operated by BROG. Under the terms of the partial settlement, BROG paid the Trust $3,490,000 to settle the imbalance insofar as it relates to some of the wells located on the Underlying Properties. The remainder of the imbalance is to be addressed through volume adjustments whereby the Trust’s Royalty will be increased by the proceeds from 50% of the overproduced parties’ interest, on a monthly basis, until the imbalance is corrected. The Trustee and its consultants remain in communication with BROG in order to determine the estimated value of the volume adjustments and the time during which the remainder of the imbalance will be corrected. BROG indicates that the volume adjustment commenced in August 2000. The Trust’s consultants continue to monitor those adjustments.

The following information was provided to the Trust by BROG. Please note that the proceedings described below apply to the collective interest of BROG and the Trust. BROG is not able to estimate the amount of any potential loss to the Trust in each of the outstanding proceedings, or the portion of any such potential loss that would be allocated to the Royalty.

Blanco Pool. This appeal arises from a MMS Demand Letter dated October 20, 1995, and bears MMS Appeal Docket No. MMS-95-0740. The demand letter challenges the “valuation benchmark” utilized by BROG for gas sold by BROG from the “Blanco Pool” during the audit period of January 1, 1989 through December 31, 1991. BROG paid royalties on sales to its marketing affiliate based on “gross proceeds” received by BROG from its affiliate. The demand letter states that BROG paid incorrectly under MMS regulations. The MMS methodology in calculating the amounts demanded does not attempt to trace resale proceeds. Instead, MMS’ auditors use published index prices at pipeline interconnect points in the San Juan Basin as a proxy for actual comparable sales, and net out certain actual costs to move the gas to those index points. While BROG had deducted prevailing field transportation rates in computing its monthly prices in the San Juan Basin, the auditors limited the deduction to the actual rate paid to El Paso Natural Gas under a “backhaul” agreement. The demand letter directs BROG to pay additional royalties of $518,304, to recalculate royalties in accordance with the MMS’ interpretation of the regulations and to pay the difference between total royalty due and royalty paid.

Affiliate Proceeds Demand — Conventional Gas. This appeal arises from a MMS demand letter dated June 9, 1997, and bears MMS Appeal Docket No. MMS-97-0168. The demand letter is a blanket demand relating to all of BROG’s non-coalbed methane gas production nationwide for the audit period of January 1, 1989 through December 31, 1994. The demand letter is based primarily on the MMS theory that royalties are to be based on BROG’s marketing affiliate gross proceeds rather than BROG’s gross proceeds (e.g. the affiliate resale proceeds issue). The demand letter directs BROG to recalculate its royalties on these sales using a netback calculation of the proceeds of the affiliate, and pay the difference between total royalties due under such calculation and the royalties actually paid by BROG. This demand letter is in furtherance of the demand letter described in the prior paragraph.

Coalbed Methane. This appeal arises from a MMS demand letter dated October 28, 1996, and bears MMS Appeal Docket No. MMS-96-0437. The demand letter relates to BROG’s coalbed methane production from the Northeast Blanco Unit for the audit period of May 1, 1990 through December 31, 1993, and from the San Juan 30-6 Unit for the audit period of January 1, 1989 through December 31, 1991. Like the Blanco Pool demand letter, the demand letter does not attempt to trace resale proceeds. The issues are whether MMS should bear its share of CO₂ extraction costs and, if so, whether the costs should be based on market rates or actual costs of the system, and whether MMS’ share of transportation costs (which MMS does not dispute it must bear) should be based on market rates or actual costs of the system. BROG is directed to pay additional royalties of $3,600,584 for underpayment of royalty for gas produced from the units mentioned above, to recalculate royalties for gas produced from other federal leases in accordance with MMS’ interpretation of the regulations and to pay the difference between total royalty due and royalty paid.

Due to the similarity of the claims in the Blanco Pool, Affiliate Proceeds Demand and the Coalbed Methane administrative appeals, to the claims in the suits in the In re Natural Gas Royalties qui tam litigation described below, settlement discussions between BROG and the federal government in the gas qui tam litigation will, if successful, include the settlement of each of the MMS Proceedings.

BROG and other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits were consolidated during 1999 and 2000 for pre-trial proceedings by the United States Judicial Panel on Multidistrict Litigation in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants underpaid royalties on natural gas and natural gas liquids produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal

regulations and that the forms filed by defendants with the MMS reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including BROG.

If successful, this litigation could result in a decrease in royalty income received by the Trust. The plaintiffs and the intervenor have not specified in their pleadings the amount of damages they seek from BROG. The Trust has been informed that BROG has established a substantial reserve for potential liability arising from this litigation. However, at this time, no estimate can be made as to the amount of any potential loss in this litigation, or the portion, if any, of such potential loss that would be allocated to the Trust’s interest. Any proposed allocation of loss to the Trust will be reviewed by the Trust’s consultants.

In September 1999, BROG was served with a class action petition styled Quinque Operating Company on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, Kansas, naming certain of its current or former affiliates as defendants, along with hundreds of other gas production and gas pipeline companies. On February 21, 2002, the District Court granted leave for plaintiffs to file a third amended class action petition substituting in new class representative plaintiffs thereby changing the style of the case to Will Price, Stixon Petroleum, Inc. and Thomas F. Boles on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, Kansas. The petition alleges that the defendants engaged in the mismeasurement of volumes and wrongful analysis of heating content of natural gas and engaged in other activities which resulted in the underpayment of revenue owed to working interest owners, royalty interest owners, overriding royalty interest owners and state taxing authorities. If successful, this litigation could result in a decrease in royalty income received by the Trust. At this time, no estimate can be made as to the amount of any loss in this litigation, or the portion of any such potential loss that would be allocated to the Trust. Any proposed allocation of loss to the Trust will be reviewed by the Trust’s consultants.

No matters were submitted to a vote of Unit Holders, through the solicitation of proxies or otherwise, during the fourth quarter ended December 31, 2003.

The information under “Units of Beneficial Interest” at page 1 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2003, is herein incorporated by reference. The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

The “Description of the Properties” and “Trustee’s Discussion and Analysis” at pages 4 through 10 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2003, are herein incorporated by reference.

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

The Financial Statements of the Trust and the notes thereto at page 12 et seq., of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2003, are herein incorporated by reference.

Within the two most recent fiscal years, there have been no changes in and disagreements with the Trust’s independent accountants.

The Trust maintains a system of disclosure controls and procedures that is designed to provide reasonable assurance that information required to be disclosed in the Trust’s filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by BROG to the Trustee and its employees who participate in the preparation of the Trust’s periodic reports to allow timely decisions regarding disclosure. Due to the pass-through nature of the Trust, BROG provides much of the information disclosed in this Form 10-K and the other periodic reports filed by the Trust with the SEC.

The Indenture does not require BROG to update or provide information to the Trust. Under the Conveyance transferring the Royalty to the Trust, BROG is obligated to provide the Trust with certain information concerning calculations of net proceeds owed to the Trust, among other information. The information which BROG elects to disclose to the Trust, and which is included in the Trust’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, is broader than the information which BROG is required to disclose to the Trust pursuant to the Conveyance. Pursuant to the settlement of the litigation described in Note 5 to the Financial Statements, BROG agreed to new, more formal financial reporting and audit procedures as compared to those provided in the Conveyance.

The Trustee receives periodic updates from BROG regarding activities related to the Trust. Accordingly, the Trust’s ability to timely report certain information required to be disclosed in the Trust’s periodic reports is dependent on BROG’s timely delivery of such information to the Trust. In order to help

ensure the accuracy and completeness of the information required to be disclosed in the Trust’s periodic reports, the Trust employs independent public accountants, joint interest auditors, marketing consultants, attorneys and petroleum engineers. These outside professionals assist the Trustee in reviewing and compiling this information for inclusion in this Form 10-K and the other periodic reports provided by the Trust to the SEC.

The Trustee has evaluated the Trust’s disclosure controls and procedures as of December 31, 2003, and has determined that, subject to BROG’s delivery of timely and accurate information to the Trust, such disclosure controls and procedures are effective. The Trustee has not reviewed the Trust’s disclosure controls and procedures in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Trust Indenture provide for, officers, a board of directors or an independent audit committee.

During the three month period ended December 31, 2003, there were no changes in the Trust’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) that materially affected or are reasonably likely to materially affect the Trust’s internal control over financial reporting.

The Trust has no directors, executive officers or employees; the Trust is managed by a corporate trustee. Accordingly, the Trust does not have an audit committee, audit committee financial expert or a code of ethics applicable to executive officers. The Trustee, however, has adopted a policy regarding standards of conduct and conflicts of interest applicable to all directors, officers and employees of the Trustee. The Trustee is a corporate trustee which may be removed, with or without cause, at a meeting of the Unit Holders, by the affirmative vote of the holders of a majority of all the Units then outstanding.

The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions which occurred in 2003, except that Alpine Capital, L.P. filed a Form 4 on November 12, 2003 disclosing, among other things, two transactions that were not reported on a timely basis.

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not have a compensation committee or maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.


(1)	Under the Trust Indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first


	$100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates for time in excess of 300 hours annually. As of January 1, 2003, the administrative fee due under items (i) and (ii) above will not be less than $36,000 per year (as adjusted annually to reflect the increase (if any) in the Producers Price Index as published by the U.S. Department of Labor, Bureau of Labor Statistics).

(2)	During 2002, TexasBank served as Trustee for the period September 30, 2002 through December 31, 2002.

(3)	During 2002, Bank One, N.A. served as Trustee for the period January 1, 2002 through September 30, 2002.

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

(a) Security Ownership of Certain Beneficial Owners. The following table sets forth, as of March 9, 2004, information with respect to each person known to beneficially own more than 5% of the outstanding Units of the Trust:


(1)	The source of this information is a Form 13F for the quarter ended September 30, 1999, filed by Societe General Asset Management Corp. with the SEC.

(b) Security Ownership of Trustee. As of March 9, 2004, TexasBank owned no Units.

The Trust has no directors or executive officers and is not empowered to carry on any business activity. Accordingly, there are no relationships or related transactions to which the Trust was a party that are required to be disclosed. See Item 11 for the remuneration received by the Trustee during the year ended December 31, 2003 and Item 12 for information concerning Units owned by TexasBank.

The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P., the Trust’s principal accountants, for the audit of the Trust’s annual financial statements for the fiscal years ended December 31, 2003 and 2002 and fees billed for other services rendered to the Trust by Weaver and Tidwell, L.L.P. during those periods.

Audit Fees consist of fees billed for professional services rendered for the audit of the Trust’s annual financial statements, review of the interim financial statements included in the Trust’s quarterly reports and

Audit-Related Fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements. This category includes fees related to audit and attest services not required by statute or regulations and consultations concerning financial accounting and reporting standards.

Tax Fees consist of fees for professional services billed for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance, return preparation, preparation of the B-schedules and tax booklet.

All Other Fees consist of fees billed for products and services other than the services reported above.

The Trust has no directors or executive officers. Accordingly, the Trust does not have an audit committee and there are no audit committee pre-approval policies or procedures relating to services provided by the Trust’s independent accountants. Pursuant to the terms of the Trust Indenture, the Trustee engages and approves all services rendered by the Trust’s independent accountants.

Included in Part II of this Annual Report on Form 10-K by reference to the Trust’s Annual Report to Unit Holders for the year ended December 31, 2003:


	Independent Auditors’ Reports
	Statements of Assets, Liabilities and Trust Corpus
	Statements of Distributable Income
	Statements of Changes in Trust Corpus
	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 given in the financial statements or notes thereto.

The Trust filed a report on Form 8-K on October 21, 2003. In the report, the Trust reported, under Item 12, that on October 21, 2003, it had issued a press release announcing a monthly cash distribution to Unit Holders.

The Trust filed a report on Form 8-K on November 20, 2003. In the report, the Trust reported, under Item 12, that on November 17, 2003, it had issued a press release announcing a monthly cash distribution to Unit Holders.

The Trust filed a report on Form 8-K on December 19, 2003. In the report, the Trust reported, under Item 12, that on December 19, 2003, it had issued a press release announcing a monthly cash distribution to Unit Holders.


	*	A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.

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.


	*	A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.


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

		For the fiscal year ended December 31, 2003

or

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

		For the transition period from to


Texas		75-6279898
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

TexasBank, Trust Department 2525 Ridgmar Boulevard, Suite 100 Fort Worth, Texas (Address of principal executive offices)		76116 (Zip Code)


Title of Each Class		Name of Each Exchange on Which Registered

Units of Beneficial Interest		New York Stock Exchange


PART I
	Item 1. Business
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Units, Related Security Holder Matters and Issuer Purchases of Units
	Item 6. Selected Financial Data
	Item 7. Trustee’s Discussion and Analysis of Financial Condition and Results of Operation
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9A. Controls and Procedures
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Security Holder Matters
	Item 13. Certain Relationships and Related Transactions
	Item 14. Principal Accountant Fees and Services
PART IV
	Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURE
EXHIBIT INDEX
Annual Report to Unit Holders
Consent of Cawley, Gillespie & Associates, Inc.
Certification of Vice President & Trust Officer
Certification of Vice President & Trust Officer



	2003				2002				2001

	Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)		Oil (Bbls)		Gas (Mcf)

Production		43,123		25,922,650		40,215		19,584,056		42,056		19,272,021
Average Price	$	26.11	$	3.93	$	20.90	$	2.32	$	24.99	$	4.61

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	Crude			Natural
	Oil			Gas
	(Bbls)			(Mcf)

Reserves as of December 31, 2000		682			302,907

Revisions of previous estimates		(272	)		(116,270	)
Extensions, discoveries and other additions		15			9,450
Production		(42	)		(19,272	)


Reserves as of December 31, 2001		383			176,815

Revisions of previous estimates		86			60,402
Extensions, discoveries and other additions		19			17,833
Production		(40	)		(19,584	)


Reserves as of December 31, 2002		448			235,466

Revisions of previous estimates		(31	)		17,045
Extensions, discoveries and other additions		8			14,021
Production		(43	)		(25,923	)


Reserves as of December 31, 2003		382			240,609


Item 4.	*Submission of Matters to a Vote of Security Holders*


Item 5.	*Market for Registrant’s Units, Related Security Holder Matters and Issuer Purchases of Units*


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


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


Item 8.	*Financial Statements and Supplementary Data*


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


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


Name of Individual			Capacities in		Cash
or Entity	Year		Which Served		Compensation

TexasBank		2003		Trustee	$	234,064	(1)
TexasBank(2)		2002		Trustee	$	44,316
Bank One, N.A.(3)		2002		Trustee	$	148,399
Bank One N.A.		2001		Trustee	$	125,259


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


Item 1.	*Business*


Item 2.	*Properties*


	2003			2002			2001

Balance, January 1	$	411,882		$	173,846		$	818,212
Revisions of prior-year estimates, change in prices and other		106,935			233,062			(652,337	)
Extensions, discoveries and other additions		29,693			25,642			7,519
Accretion of discount		41,188			17,385			81,821
Royalty income		(91,997	)		(38,053	)		(81,369	)

Balance, December 31	$	497,701		$	411,882		$	173,846



	2003				2002				2001

	Estimated				Estimated				Estimated
	Future		Present		Future		Present		Future		Present
	Net		Value at		Net		Value at		Net		Value at
	Revenue		10%		Revenue		10%		Revenue		10%

Total Proved	$	899,477	$	497,701	$	737,639	$	411,882	$	290,582	$	173,846
Proved Developed	$	818,782	$	458,224	$	661,634	$	378,285	$	266,834	$	164,164
Total Proved Per Unit	$	19.30	$	10.68	$	15.83	$	8.84	$	6.23	$	3.73


		Amount and Nature
		of Beneficial
Name and Address		Ownership		Percent of Class

Societe General Asset Management Corp.(1)			3,905,000 Units		8.7	%
	1221 Avenue of the Americas
	New York, New York 10020


Item 13.	*Certain Relationships and Related Transactions*


	2003		2002

Audit Fees	$	29,730	$	25,475
Audit-Related Fees		-0-		-0-
Tax Fees		6,470		12,325
All Other Fees		-0-		-0-

Total	$	36,200	$	37,800


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


Exhibit
Number			Description

	4	(a)	Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.*
	4	(b)	Net Overriding Royalty Conveyance from Southland Royalty Company to the Forth Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
	4	(c)	Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.*
	13		Registrant’s Annual Report to Unit Holders for the fiscal year ended December 31, 2003.**
	23		Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
	31		Certification required by Rule 13a-14(a), dated March 15, 2004, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee for the Trust.**
	32		Certification required by Rule 13a-14(b), dated March 15, 2004, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank on behalf of TexasBank, the Trustee of the Trust.**