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UNITED STATES SECURITIES AND EXCHANGE
COMMISSION

Washington, D.C. 20549




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Form 10-K

|           |  |                                                                                             
|---------- |  | --------------------------------------------------------------------------------------------
|(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                                             

Commission file number 1-8032

San Juan Basin Royalty Trust

(Exact name of registrant as specified in
the


Amended and Restated San Juan Basin
Royalty Trust Indenture)


|                                                                                                                                    |  |                                         
|----------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------
|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)                         

(Registrants telephone number, including
area code)

(866) 809-4553


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

|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of Each Class          |  | Name of Each Exchange on Which Registered
|                             |  |                                          
|Units of Beneficial Interest |  | New York Stock Exchange                  

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

None


(Title of Class)


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.

DOCUMENTS INCORPORATED BY REFERENCE

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.



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TABLE OF CONTENTS



|                                                |                                                                                                             |  |  |  |  |  |  | 
|----------------------------------------------- | ----------------------------------------------------------------------------------------------------------- |  |  |  |  |  |  | 
|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



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PART I

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.






|        |         
|------- | --------
|Item 1. | Business

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.

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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

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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.






|        |           
|------- | ----------
|Item 2. | Properties

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.

Producing Acreage, Wells and
Drilling

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

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$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

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


Oil and Gas Production

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:

|              |  |            |        |           |  |            |            |           |  |            |        |           |  |   |            |  |  |   |        |  |  |   |            | 
|------------- |  | ---------- | ------ | --------- |  | ---------- | ---------- | --------- |  | ---------- | ------ | --------- |  | - | ---------- |  |  | - | ------ |  |  | - | ---------- | 
|              |  |            |        |           |  |           
|              |  | 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       | 

Pricing Information

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.

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Oil and Gas Reserves

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):

|                                            |  |        |      |         |  |  |          |  
|------------------------------------------- |  | ------ | ---- | ------- |  |  | -------- | -
|                                            |  | 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  |  
|                                            |  |        |      |         |  |  |          |  

6



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##### Table of Contents



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):

|     |  |        |     |         |  |  |         | 
|---- |  | ------ | --- | ------- |  |  | ------- | 
|     |  | Crude  |     | Natural
|     |  | Oil    |     | Gas    
|     |  | (Bbls) |     | (Mcf)  
|     |  |        |     |        
|2003 |  |        | 349 |         |  |  | 218,266 | 
|2002 |  |        | 415 |         |  |  | 209,665 | 
|2001 |  |        | 356 |         |  |  | 162,577 | 

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):

|                                                                  |  |      |         |      |  |      |         |   |  |   |          |  
|----------------------------------------------------------------- |  | ---- | ------- | ---- |  | ---- | ------- | - |  | - | -------- | -
|                                                                  |  | 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  |  
|                                                                  |  |      |         |      |  |      |         |   |  |   |          |  

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.

7



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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):

|                      |  |           |         |          |  |           |         |          |  |           |         |          |  |   |         |  |  |   |         |  |  |   |         | 
|--------------------- |  | --------- | ------- | -------- |  | --------- | ------- | -------- |  | --------- | ------- | -------- |  | - | ------- |  |  | - | ------- |  |  | - | ------- | 
|                      |  |           |         |          |  |          
|                      |  | 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    | 

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.

Regulation

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.



| |                                   
| | ----------------------------------
| | Federal Natural Gas
    Regulation

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

8



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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.



| |                      
| | ---------------------
| | Section 29 Tax Credit

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

9



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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.



| |                 
| | ----------------
| | Other Regulation

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.






|        |                  
|------- | -----------------
|Item 3. | Legal Proceedings

Settlements

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.

Administrative Proceedings

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.

10



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##### Table of Contents





| |                
| | ---------------
| | MMS Proceedings

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.

Litigation



| |                                                   
| | --------------------------------------------------
| | In re Natural Gas Royalties Qui Tam
    Litigation

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

11



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##### Table of Contents



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.



| |                   
| | ------------------
| | Quinque Litigation

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.






|        |                                                        
|------- | -------------------------------------------------------
|Item 4. | Submission of Matters to a Vote of Security
    Holders

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.




PART II






|        |                                                                                                     
|------- | ----------------------------------------------------------------------------------------------------
|Item 5. | Market for Registrants Units, Related
    Security Holder Matters and Issuer Purchases of
    Units

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.






|        |                        
|------- | -----------------------
|Item 6. | Selected Financial Data

|                              |  |      |            |      |  |      |            |      |  |      |            |  |  |   |            |  |  |   |            | 
|----------------------------- |  | ---- | ---------- | ---- |  | ---- | ---------- | ---- |  | ---- | ---------- |  |  | - | ---------- |  |  | - | ---------- | 
|                              |  | 2003 |            | 2002 |  | 2001 |            | 2000 |  | 1999
|                              |  |      |            |      |  |      |            |      |  |     
|Royalty income                |  | $    | 91,997,262 |      |  | $    | 38,053,281 |      |  | $    | 81,368,723 |  |  | $ | 60,044,773 |  |  | $ | 32,626,966 | 
|Distributable income          |  |      | 90,357,837 |      |  |      | 36,417,967 |      |  |      | 80,126,202 |  |  |   | 59,188,932 |  |  |   | 31,795,667 | 
|Distributable income per Unit |  |      | 1.938644   |      |  |      | 0.781354   |      |  |      | 1.719123   |  |  |   | 1.269909   |  |  |   | 0.682182   | 
|Distributions per Unit        |  |      | 1.938644   |      |  |      | 0.781354   |      |  |      | 1.719123   |  |  |   | 1.269909   |  |  |   | 0.682182   | 
|Total assets, December 31     |  |      | 36,905,104 |      |  |      | 37,972,696 |      |  |      | 38,051,369 |  |  |   | 47,659,746 |  |  |   | 49,048,652 | 

12



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|        |                                                                                      
|------- | -------------------------------------------------------------------------------------
|Item 7. | Trustees Discussion and Analysis of
    Financial Condition and Results of Operation

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.






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

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.






|        |                                                
|------- | -----------------------------------------------
|Item 8. | Financial Statements and Supplementary
    Data

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.






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

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






|         |                        
|-------- | -----------------------
|Item 9A. | Controls and Procedures

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

13



---



##### Table of Contents



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.




PART III






|         |                                                       
|-------- | ------------------------------------------------------
|Item 10. | Directors and Executive Officers of the
    Registrant

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.

Section 16(a) Beneficial Ownership
Reporting Compliance

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.






|         |                       
|-------- | ----------------------
|Item 11. | Executive Compensation

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.

During the past three years the Trustee received
total remuneration as follows:

|                   |  |      |      |               |  |              |         |  |  |   |         |    
|------------------ |  | ---- | ---- | ------------- |  | ------------ | ------- |  |  | - | ------- | ---
|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 |    



---



|    |                                                                                                                                                                                                               
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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

14



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##### Table of Contents



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|    | $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.                                                                                                                                                                                                                                                                                                                                                                                                                                              






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

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:

|                                          |                             |                   |                 |                  |  |  |     |   | 
|----------------------------------------- | --------------------------- | ----------------- | --------------- | ---------------- |  |  | --- | - | 
|                                          |                             | 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    |                   |                 |                  |  |  |     |   | 



---



|    |                                                                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------
|(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.






|         |                                                   
|-------- | --------------------------------------------------
|Item 13. | Certain Relationships and Related
    Transactions

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.






|         |                                           
|-------- | ------------------------------------------
|Item 14. | Principal Accountant Fees and
    Services

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.

|                   |  |      |        |      |  |   |        | 
|------------------ |  | ---- | ------ | ---- |  | - | ------ | 
|                   |  | 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 | 
|                   |  |      |        |      |  |   |        | 

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

15



---



##### Table of Contents



services that are normally provided by Weaver and
Tidwell, L.L.P. in connection with statutory and regulatory
filings or engagements.


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.




PART IV






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

The following documents are filed as a part of
this Annual Report on Form 10-K:

Financial Statements

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

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.

Reports on Form 8-K

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.

16



---



##### Table of Contents



Exhibits

|        |    |             |  |                                                                                                                                                                                                                                                                                                                                                                                                                                   
|------- | -- | ----------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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.**                                                                                                                                                                                                                                



---



| |   |                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | * | 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.



|   |                
|-- | ---------------
|** | Filed herewith.

17



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##### Table of Contents






SIGNATURE

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.



| |                             
| | ----------------------------
| | TEXASBANK, AS TRUSTEE OF THE
| | SAN JUAN BASIN ROYALTY TRUST



| |     |                     
| | --- | --------------------
| | By: | /s/ LEE ANN ANDERSON

| |                                 
| | --------------------------------
| |                                 
| | Lee Ann Anderson                
| | Vice President and Trust Officer

Date: March 15, 2004

(The Trust has no directors or executive officers)



---



##### Table of Contents






EXHIBIT INDEX

|        |    |             |  |                                                                                                                                                                                                                                                                                                                                                                                                                                   
|------- | -- | ----------- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|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.**                                                                                                                                                                                                                               



---



| |   |                                                                                                                                                                                                
| | - | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | * | 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.



|   |                
|-- | ---------------
|** | Filed herewith.