<PAGE>

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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549
                             ---------------------

                                   FORM 10-K

<Table>
<C>        <S>
(Mark One)
   [X]     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
           SECURITIES EXCHANGE ACT OF 1934

           FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

                                  OR


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

           FOR THE TRANSITION PERIOD FROM           TO
</Table>

                         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)

<Table>
<S>                                              <C>
                     TEXAS                                          75-6279898
        (State or other jurisdiction of                          (I.R.S. Employer
         incorporation or organization)                        Identification No.)

          TEXASBANK, TRUST DEPARTMENT
       2525 RIDGMAR BOULEVARD, SUITE 100
               FORT WORTH, TEXAS                                      76116
    (Address of principal executive offices)                        (Zip Code)
</Table>

                                 (866) 809-4553
              (Registrant's telephone number, including area code)

          SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

<Table>
<Caption>
              TITLE OF EACH CLASS                   NAME OF EACH EXCHANGE ON WHICH REGISTERED
              -------------------                   -----------------------------------------
<S>                                              <C>
          Units of Beneficial Interest                       New York Stock Exchange
</Table>

          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 [X]    No [ ]

    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.  Yes [X]    No [ ]

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

    State the aggregate market value of the Units of Beneficial Interest held by
non-affiliates of the Registrant as of June 28, 2002: $515,959,372.

    At March 25, 2003, 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
pages 5 and 6; "Trustee's Discussion and Analysis" at pages 7, 8 and 9; "Results
of the 4th Quarters of 2002 and 2001" at page 10; and "Statements of Assets,
Liabilities and Trust Corpus," "Statements of Distributable Income," "Statements
of Change in Trust Corpus," "Notes to Financial Statements," and "Independent
Auditor's Report" at page 11 et seq., in registrant's Annual Report to Unit
Holders for the year ended December 31, 2002 are incorporated herein by
reference for Item 2 (Properties) and Item 3 (Legal Proceedings) of Part I of
this Report, and Item 5 (Market for Units of the Trust and Related Security
Holder Matters), Item 7 (Management'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.
--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

                                     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," "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 such material with, or furnishing it to, the SEC.

     On October 23, 1980, the stockholders of Southland Royalty approved and
authorized that company's conveyance of a 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 consisting of a 75% net overriding royalty interest carved out
of that company's oil and gas leasehold and royalty interests (the "Underlying
Interests") in properties located in the San Juan Basin of northwestern New
Mexico (the "Underlying Properties"). The conveyance of this net overriding
royalty interest (the "Royalty") was made 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 those properties and
interests 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."

     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.

     In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington
Northern Inc. ("BNI"). In 1988, BNI transferred its natural resource operations
to Burlington Resources Inc. ("BRI") as a result of

                                        2
<PAGE>

which Southland Royalty became a wholly-owned indirect subsidiary of BRI. As a
result of these transactions, Meridian Oil, Inc. ("MOI") also became an indirect
subsidiary of BRI. Effective January 1, 1996, Southland Royalty, a wholly-owned
subsidiary of MOI, was merged with and into MOI, by which action the separate
corporate existence of Southland Royalty ceased to exist and MOI survived and
succeeded to the ownership of all of the assets, rights, powers and privileges
and assumed all of the liabilities and obligations of Southland Royalty.
Subsequent to the merger, MOI changed its name to BROG.

     The term "net proceeds," as used in the November 3, 1980 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 Interests) from the sale of
the production attributable to the Underlying Interests subject to certain
adjustments. "Production costs" generally means costs incurred on an accrual
basis by BROG in operating its properties and interests out of which the Royalty
was carved, 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 these properties
and interests 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.

     Certain of the Underlying Interests 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 a settlement 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. BROG, however, can sell its interest in the Underlying
Properties.

     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. The identity of Unit Holders entitled
to a distribution will generally be determined as of the last business day of
each calendar month (the "monthly record date"). The amount of each monthly
distribution will generally be determined and announced ten days before the
monthly record date. Unit Holders of record as of the monthly record date will
be entitled to receive the calculated monthly distribution amount for each month
on or before ten business days after 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.

                                        3
<PAGE>

     Based on its 1999 year-end review, BROG determined that it had undercharged
the Trust for both capital expenditures and lease operating charges related to
properties burdened by the Trust but not operated by BROG. In April and May of
2000, BROG passed through to the Trust additional charges of $652,303 in capital
expenditures and $1,689,509 in lease operating charges related to the
undercharged non-operated properties. The Trust's consultants have reviewed
BROG's cost reporting data and confirmed that these additional charges were
appropriate.

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. 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 Item 2 is based
upon data and information furnished to the Trustee by BROG.

PRODUCING ACREAGE, WELLS AND DRILLING

     The Underlying Interests 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. Based upon information received from the Trust's
independent petroleum engineers, as of December 31, 2002, the Trust properties
contain 3,738 gross (1,135 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. For
additional information concerning coal seam gas, the "Description of the
Properties" section of the Trust's Annual Report to security holders for the
year ended December 31, 2002, is herein incorporated by reference.

     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 2002, BROG announced an estimated capital budget for the
Underlying Properties of $17.1 million. During the year the estimate was
initially reduced to $12.4 million and ultimately increased to $19.0 million.
BROG's capital plan for the Underlying Properties for 2002 estimated 397
projects, including the drilling of 54 new wells operated by BROG and 26 wells
operated by third parties. In 2002, BROG actually participated in 339 projects,
including 41 new wells operated by BROG and 12 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.

     An aggregate of $21.5 million in capital expenditures were reported by BROG
in calculating payments to the Trust for 2002. This amount included
approximately $10.1 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. Also, for 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
$11.4 million for 2002 budgeted projects were used in calculating distributable
income in calendar year 2002, and approximately $3.6 million in capital
expenditures have been used in calculating distributions for the first three
months of 2003. Therefore, an additional approximately $4.0 million in capital
expenditures for 2002 projects remains to be spent.

                                        4
<PAGE>

     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, 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.

     During 2001, in calculating the net proceeds to the Trust, BROG deducted
approximately $33 million of capital expenditures for projects, including
drilling and completion of 92 gross (36.33 net) conventional wells, recompletion
of 33 gross (18.18 net) conventional wells, 13 gross (2.85 net) miscellaneous
capital projects, three gross (2.34 net) restimulations, 56 gross (8.40 net)
conventional payadds, ten gross (1.52 net) coal seam wells, four gross (1.61
net) coal seam well recompletions, one gross (.88 net) coal seam payadd, six
gross (.04 net) coal seam recavitations and facilities maintenance. There were
100 gross (32.47 net) new conventional wells, 31 gross (13.47 net) conventional
well recompletions, two gross (.87 net) miscellaneous conventional capital
projects, nine gross (3.17 net) conventional payadds, 15 gross (1.09 net)
conventional restimulations, 12 gross (5.36 net) coal seam wells, seven gross
(4.11 net) coal seam recompletions, two gross (.02 net) coal seam restimulations
and six gross (.29 net) miscellaneous coal seam capital projects in progress as
of December 31, 2001.

     BROG has informed the Trust that its projections for capital expenditures
for the Underlying Properties in 2003 is estimated at $14.1 million. BROG
anticipates 351 projects, including the drilling of 38 new wells to be operated
by BROG and 26 wells to be operated by third parties. Of the new BROG operated
wells, 14 are projected to be conventional wells completed to the Pictured
Cliffs, Mesaverde, and/or Dakota formations, and the remaining 24 are projected
as coal seam gas wells to be completed in the Fruitland Coal formation. A total
of 21 of the wells operated by third parties are projected to be conventional
wells and the remaining five are to be coal seam wells. BROG projects
approximately $10.5 million to be spent on new wells, and $3.6 million to be
expended in working over existing wells and in the maintenance and improvement
of production facilities.

     In October 2002, the New Mexico Oil Conservation Division approved reduced,
160-acre spacing in selected portions of the Fruitland Coal formation. BROG has
informed the Trust that, principally as a result of this approval, its budget
for 2003 reflects a focus on the Fruitland Coal formation. 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. The New Mexico Oil Conservation has asked BROG and other interested
parties to study over the next year whether the change in spacing requirements
should be expanded to cover other portions of that reservoir. Eighty-acre
spacing has been permitted in the Mesaverde formation since 1997.

     BROG has previously informed the Trust that increases in its capital
program, particularly in 2001 and 2002, were designed to offset the natural
decline in production from the Underlying Properties. BROG has reported
favorable results in this effort in that natural gas production for calendar
year 2002 averaged approximately 127 MMcf per day, as compared to average
production of approximately 121 MMcf per day for calendar 2001, and 116 MMcf per
day for calendar 2000.

     BROG indicates its budget for 2003 reflects continued significant
development of properties in which the Trust's net overriding royalty interest
is relatively high, a sustained focus on conventional formations, including
infill drilling to the Mesaverde and Dakota formations, development of the
Fruitland Coal formation and multiple formation completions.

                                        5
<PAGE>

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, 2002 were as follows:

<Table>
<Caption>
                               2002                    2001                    2000
                       ---------------------   ---------------------   ---------------------
                         OIL                     OIL                     OIL
                       (BBLS)     GAS (MCF)    (BBLS)     GAS (MCF)    (BBLS)     GAS (MCF)
                       -------   -----------   -------   -----------   -------   -----------
<S>                    <C>       <C>           <C>       <C>           <C>       <C>
Production...........   40,215    19,584,056    42,056    19,272,021    47,441    20,317,750
Average Price........  $ 20.90   $      2.32   $ 24.99   $      4.61   $ 24.66   $      2.99
</Table>

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 properties from which the Royalty was
carved totaled 46,206,298 Mcf during 2002.

     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
which are subject to the Royalty (the "Trust" gas, oil and/or natural gas
liquids) as follows:

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

          (ii) BROG will continue to market the Trust oil and natural gas
     liquids 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 Trust gas 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, 2002 for further discussion of
this settlement and its impact on the Trust.

     BROG has entered into two contracts for the sale of all Trust gas. These
contracts provide for (i) the sale of Trust gas in two packages to Duke Energy
and Marketing, L.L.C. and PNM Gas Services, respectively, (ii) the delivery of
Trust gas at various delivery points over a period commencing April 1, 2002, and
ending March 31, 2004, and (iii) the sale of Trust gas at prices which fluctuate
in accordance with published indices for gas sold in the San Juan Basin of New
Mexico.

     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.

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 Item:

          "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

                                        6
<PAGE>

     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, 2000, 2001 and 2002 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1999 to
December 31, 2002 (in thousands):

<Table>
<Caption>
                                                              CRUDE    NATURAL
                                                               OIL       GAS
                                                              (BBLS)    (MCF)
                                                              ------   --------
<S>                                                           <C>      <C>
Reserves as of December 31, 1999............................    450     214,215
                                                               ----    --------
Revisions of previous estimates.............................    199      73,803
Extensions, discoveries and other additions.................     80      36,207
Production..................................................    (47)    (20,318)
                                                               ----    --------
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
                                                               ----    --------
</Table>

     Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 2002, 2001 and 2000 were as follows (in thousands):

<Table>
<Caption>
                                                              CRUDE    NATURAL
                                                               OIL       GAS
                                                              (BBLS)    (MCF)
                                                              ------   -------
<S>                                                           <C>      <C>
2002........................................................   415     209,665
2001........................................................   356     162,577
2000........................................................   624     277,459
</Table>

     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

                                        7
<PAGE>

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 2002, 2001 and 2000 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):

<Table>
<Caption>
                                                         2002       2001       2000
                                                       --------   --------   --------
<S>                                                    <C>        <C>        <C>
Balance, January 1...................................  $173,846   $818,212   $229,721
Revisions of prior-year estimates, change in prices
  and other..........................................   233,062   (652,337)   530,811
Extensions, discoveries and other additions..........    25,642      7,519     94,753
Accretion of discount................................    17,385     81,821     22,972
Royalty income.......................................   (38,053)   (81,369)   (60,045)
                                                       --------   --------   --------
Balance, December 31.................................  $411,882   $173,846   $818,212
                                                       --------   --------   --------
</Table>

     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 $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 downward revision in reserve quantities for
2001 as compared to 2000 is primarily due to significantly lower oil and gas
prices in December 2001 as compared to December 2000.

     December average prices of $6.18 per Mcf of conventional gas, $4.03 per Mcf
of coal seam gas and $24.67 per Bbl of oil were used at December 31, 2000, in
determining future net revenue.

                                        8
<PAGE>

     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, 2002, 2001 and 2000 (in thousands except amounts per Unit):

<Table>
<Caption>
                                      2002                   2001                   2000
                              --------------------   --------------------   ---------------------
                              ESTIMATED              ESTIMATED              ESTIMATED
                               FUTURE     PRESENT     FUTURE     PRESENT      FUTURE     PRESENT
                                 NET      VALUE AT      NET      VALUE AT      NET       VALUE AT
                               REVENUE      10%       REVENUE      10%       REVENUE       10%
                              ---------   --------   ---------   --------   ----------   --------
<S>                           <C>         <C>        <C>         <C>        <C>          <C>
Total Proved................  $737,639    $411,882   $290,582    $173,846   $1,580,837   $818,212
Proved Developed............  $661,634    $378,285   $266,834    $164,164   $1,445,557   $752,825
Total Proved Per Unit.......  $  13.85    $   7.93   $   6.23    $   3.73   $    33.92   $  17.55
</Table>

     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 as
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
include many additional factors.

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 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.

                                        9
<PAGE>

     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

     The Trust began receiving royalty income from coal seam gas wells in 1989.
Under Section 29 of the Internal Revenue Code, coal seam gas production from
wells drilled prior to January 1, 1993 (including certain wells recompleted in
coal seams formations thereafter), generally qualifies for the federal income
tax credit for producing non-conventional fuels if such production and the sale
thereof occurs before January 1, 2003. Thus, under current law, coal seam gas
production after December 31, 2002 will not qualify for the Section 29 credit.
For 2001, this tax credit was approximately $1.08 per MMBtu. For 2002, the
amount of the credit will be determined by the Treasury Department no later than
April 1, 2003, and, based on historical trends, is expected to approximate
(within a 2-3% range) the 2001 credit.

     To benefit from the credit, each Unit Holder must determine from the tax
information he receives from the Trust his pro rata share of qualifying
production of the Trust, 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 his own income tax liability, but such credit may
not reduce his 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 his 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 circumstances.

     BROG provides the Trustee with certain Section 29 tax credit information,
including qualifying coal seam volumes produced from Underlying Properties. In
1999, the Tenth Circuit Court upheld the position of the IRS and the Tax Court
that nonconventional fuel such as coal seam gas does not qualify for the Section
29 credit unless the producer received a formal certification from FERC. FERC's
certification authority expired effective January 1, 1993. However, on July 14,
2000, FERC issued a final ruling amending its regulations to reinstate certain
regulations involving well category determinations for all wells and tight
formation areas that could qualify for the Section 29 tax credit. BROG has
informed the Trustee that it will seek certification of all qualified wells and
that two additional wells were certified in 2002.

  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

     As part of the September 4, 1996 settlement of the litigation filed by the
Trustee on June 4, 1992, against BROG and Southland Royalty Company, the Trust
was entitled to certain adjustments (the "Val Verde Credit") that represented
cost reductions favorable to the Trust in the charges for coal seam gas gathered
and

                                        10
<PAGE>

treated on BROG's Val Verde system. The settlement provided that the Val Verde
Credit was applicable until the later of July 1, 2002 or until BROG no longer
owned the Val Verde facility. By correspondence dated July 15, 2002, BROG
notified the Trustee of the sale of the Val Verde facility to TEPPCO Partners,
L.P. effective July 1, 2002. Accordingly, effective July 1, 2002, the
calculation of net proceeds for gas gathered and treated at the Val Verde
facility no longer includes the Val Verde Credit. The total annual amount of the
Val Verde Credit has been estimated by the Trust's joint interest auditors as
approximately $2.0 million. The loss of the Val Verde Credit will result in
increased costs allocated to the Trust for coal seam gas gathered and treated on
the Val Verde system and accordingly, will decrease the royalty income received
by the Trust.

     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. 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 has offset the
entire $2,853,974 Jicarilla component of the settlement against amounts
otherwise distributed in payment of the Royalty, and has informed the Trust that
the $1,224,043 paid to the MMS is also allocable to the Royalty. 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 Royalty.

     In another proceeding involving BROG and the Jicarilla Apache Nation, the
MMS entered an Order to Perform on June 10, 1998, stating that, in valuing
production for royalty purposes, BROG must perform, among other things, a "dual
accounting" calculation (i.e., compute royalties on the greater of the value of
gas prior to processing or the combined value of processed residue gas and plant
products plus the value of any condensate recovered downstream without
processing). In December 2000, BROG and the Jicarilla Apache Nation entered into
a settlement resolving the issues associated with the dual accounting
calculation. Under the settlement, BROG paid $3,260,366 to the Jicarilla Apache
Nation. BROG has allocated $1,978,182 of the settlement payment to the Royalty.

     Beginning in May 2002, BROG deducted the lesser of $1 million or 50% of the
monthly net proceeds from the monthly net proceeds otherwise payable to the
Trust until an aggregate of $3,624,117 was deducted. BROG deducted $1 million
from each of the monthly net proceeds payments to the Trust in May, June and
July of 2002, and the balance in August of 2002. These deductions represented
the Trust's share of the settlements.

     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.

                                        11
<PAGE>

  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 CO(2)
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.

  JICARILLA INDIAN TRIBE PROCEEDINGS

     This appeal arises from an MMS Order to Perform dated June 10, 1998. The
Order to Perform states that, in valuing production for royalty purposes, BROG
must, among other things, perform a major portion analysis (i.e., calculate
value on the highest price paid or offered for a major portion of the gas
produced from the field where the leased lands are situated). BROG believes that
producers do not have access to prices received by other producers in a field,
so a major portion calculation must be done by MMS.

                                        12
<PAGE>

LITIGATION

  GRYNBERG LITIGATION

     In September 1998, BROG was advised by the United States Department of
Justice under an order of confidentiality that a lawsuit styled United States of
America ex rel. Jack J. Grynberg v. Burlington Resources Oil & Gas, et al.,
Civil Action No. 97-CV-189 and 190, United States District Court for the
District of Wyoming, had been filed under seal pursuant to the qui tam
provisions of the civil federal False Claims Act, and that seventy-seven similar
cases had been filed by the plaintiff against other companies. The complaint
alleges that BROG engaged in the mismeasurement of volumes and wrongful analysis
of heating content of natural gas and engaged in other activities, including the
sale of natural gas to affiliated companies, which resulted in the underpayment
of royalties to the United States. The government investigated the plaintiff's
claims, and in May 1999 issued notice that the United States would not intervene
in the case. The lawsuits have been unsealed by the court and the plaintiff has
served the complaint on BROG. This claim was subsequently consolidated into a
multi-district litigation proceeding as described below.

  IN RE NATURAL GAS ROYALTIES QUI TAM LITIGATION

     On March 28, 2000, the United States District Court for the Eastern
District of Texas, Lufkin Division, ordered that the first amended complaint in
the case of United States ex rel. M. Glenn Osterhoudt, III v. Amerada Hess, et
al., Civil Action No. 9:98CV101, in the United States District Court for the
Eastern District of Texas, Lufkin Division, and the second amended complaint in
the case of United States of America ex rel. Harrold E. (Gene) Wright v. Agip
Petroleum Burlington, et al., Civil Action No. C-5:96CV243 be unsealed and
served upon defendants, including BROG. In these lawsuits, the plaintiffs have
alleged violations of the civil False Claims Act. 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. The United States has filed an intervention in these cases as to some
of the defendants, including BROG.

     In July 2000, the United States District Court for the District of New
Mexico unsealed and BROG was served with the petition in United States of
America ex rel. Mark A. Perry v. BROG Resources, Inc., et al., Civil Action No.
9:00CV197, in the United States District Court for the District of New Mexico,
wherein plaintiff alleges violations of the civil False Claims Act. The
plaintiff claims that BROG understated the value of natural gas and natural gas
liquids produced on federal and Indian lands in connection with its computation
and reporting of royalty payments. The United States has elected to intervene in
this case, but a complaint has not been served upon BROG.

     In October 2000, the federal Judicial Panel on Multidistrict Litigation
ordered that the Wright and Osterhoudt lawsuits be transferred to the United
State District Court for the District of Wyoming for inclusion with the Grynberg
lawsuit described above in multidistrict litigation proceedings. A similar order
was issued in December 2000 transferring the Perry lawsuit. These cases have
been consolidated for pre-trial proceedings in the matter styled In re Natural
Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the
District of Wyoming.

     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 potential loss in this litigation, or the portion of any 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

                                        13
<PAGE>

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, 2002.

                                    PART II

ITEM 5. MARKET FOR UNITS OF THE TRUST AND RELATED SECURITY HOLDER MATTERS

     The information under "Units of Beneficial Interest" at page 1 of the
Trust's Annual Report to security holders for the year ended December 31, 2002,
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

<Table>
<Caption>
                                                FOR THE YEAR ENDED DECEMBER 31
                              -------------------------------------------------------------------
                                 2002          2001          2000          1999          1998
                              -----------   -----------   -----------   -----------   -----------
<S>                           <C>           <C>           <C>           <C>           <C>
Royalty income..............  $38,053,281   $81,368,723   $60,044,773   $32,626,966   $30,317,860
Distributable income........   36,417,967    80,126,202    59,188,932    31,795,667    29,498,402
Distributable income per
  Unit......................     0.781354      1.719123      1.269909      0.682182      0.635039
Distributions per Unit......     0.781354      1.719123      1.269909      0.682182      0.635039
Total assets, December 31...   37,972,696    38,051,369    47,659,746    49,048,652    53,753,582
</Table>

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATION

     The "Description of the Properties," "Trustee's Discussion and Analysis"
and "Results of the 4th Quarters of 2002 and 2001" at pages 5 through 9 of the
Trust's Annual Report to security holders for the year ended December 31, 2002,
are herein incorporated by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE 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 Trust gas, oil and/or natural gas liquids. BROG is
responsible for such marketing.

                                        14
<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

     The Financial Statements of the Trust and the notes thereto at page 10 et
seq., of the Trust's Annual Report to security holders for the year ended
December 31, 2002, are herein incorporated by reference.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

     See information contained in the Trust's Form 8-K, dated July 17, 2001,
reporting a change in accountants.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

     The Trust has no directors or executive officers. 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.

ITEM 11. EXECUTIVE COMPENSATION

     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.

     During the year ended December 31, 2002, the Trustee received total
remuneration as follows:

<Table>
<Caption>
NAME OF INDIVIDUAL OR NUMBER OF                              CAPACITIES IN       CASH
PERSONS IN GROUP                                             WHICH SERVED    COMPENSATION
-------------------------------                              -------------   ------------
<S>                                                          <C>             <C>
Bank One, N.A.(1)..........................................     Trustee        $148,399(3)
TexasBank(2)...............................................     Trustee        $ 44,316(3)
</Table>

---------------

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

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

(3) Under the Trust Indenture, the Trustee is entitled to an administrative fee
    for its administrative services and the preparation of quarterly and annual
    statements of: (i) 1/20 of 1% of the first $100 million of the annual gross
    revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the
    Trust in excess of $100 million and (ii) the Trustee's standard hourly rates
    for time in excess of 300 hours annually. Beginning January 1, 2003, in no
    case will the administrative fee due under items (i) and (ii) above 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).

                                        15
<PAGE>

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED SECURITY HOLDER MATTERS

     (a) Security Ownership of Certain Beneficial Owners.  The following table
sets forth, as of March 23, 2003, information with respect to each person known
to own beneficially more than 5% of the outstanding Units of the Trust:

<Table>
<Caption>
                                                            AMOUNT AND
                                                       NATURE OF BENEFICIAL
NAME AND ADDRESS                                            OWNERSHIP         PERCENT OF CLASS
----------------                                       --------------------   ----------------
<S>                                                    <C>                    <C>
Alpine Capital, L.P.(1)..............................    10,599,200 Units           22.7%
  201 Main Street, Suite 3100
  Fort Worth, Texas 76102
Societe General Asset Management Corp.(2)............     5,180,000 Units           11.1%
  1221 Avenue of the Americas
  New York, New York 10020
Capital Group International, Inc.(3).................     3,040,770 Units            6.5%
  Capital Guardian Trust Company
  11100 Santa Monica Blvd
  Los Angeles, CA 90025
McMorgan and Company(4)..............................     3,000,000 Units            6.4%
  1 Bush Street, Suite 800
  San Francisco, CA 94104
</Table>

---------------

(1) This information was provided to the Trust on Amendment Number 29 to
    Schedule 13D, dated March 5, 2003, as filed with the SEC by Alpine Capital,
    L.P. ("Alpine"), which indicated that these Units were beneficially owned by
    Alpine. Robert W. Bruce, III and Algenpar, Inc., are general partners of
    Alpine and have shared power to vote and dispose of the Units held by
    Alpine. The Amendment Number 27 to Schedule 13D may be reviewed for more
    detailed information concerning the matters summarized herein.

(2) This information was provided to the Trust on Amendment Number 3 to Schedule
    13G, dated January 6, 1999, as filed with the SEC. The Amendment Number 3 to
    Schedule 13G may be reviewed for more detailed information concerning the
    matters summarized herein.

(3) This information was provided to the Trust in Amendment Number 5 to Schedule
    13G dated December 31, 2002. Capital Group International, Inc. and Capital
    Guardian Trust Company each reported sole voting power over 2,131,440 Units
    and sole dispositive power over 3,040,770 Units. The Amendment Number 5 to
    Schedule 13G may be reviewed for more detailed information concerning the
    matters summarized herein.

(4) This information was provided to the Trust in a Schedule 13G dated July 12,
    1999, as filed with the SEC. The Schedule 13G may be reviewed for more
    detailed information concerning the matters summarized herein.

     (b) Security Ownership of Trustee.  As of December 31, 2002, TexasBank
owned no Units.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

     The Trust has no directors or executive officers. See Item 11 for the
remuneration received by the Trustee during the year ended December 31, 2002 and
Item 12(b) for information concerning Units owned by TexasBank.

ITEM 14. 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 Commission's

                                        16
<PAGE>

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 as
appropriate to allow timely decisions regarding required 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 Trustee receives periodic updates from BROG regarding activities
related to the Trust. Accordingly, the Trust's ability to timely report certain
information required to be disclosed in the Trust's periodic reports is
dependent on BROG's timely delivery of such information to the Trust. In order
to help ensure the accuracy and completeness of the information required to be
disclosed in the Trust's periodic reports, the Trust employs independent public
accountants, joint interest auditors, marketing consultants, attorneys and
petroleum engineers. These outside professionals assist the Trustee in reviewing
and compiling this information for inclusion in this Form 10-K and the other
periodic reports provided by the Trust to the SEC.

     The Trustee has evaluated the Trust's disclosure controls and procedures
within the 90 days prior to the filing of this Annual Report on Form 10-K 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.

     Subsequent to the Trustee's evaluation, there were no significant changes
in internal controls or other factors that could significantly affect internal
controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.

                                    PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     The following documents are filed as a part of this Report:

FINANCIAL STATEMENTS

     Included in Part II of this Report by reference to the Annual Report of the
Trust for the year ended December 31, 2002:

     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

     On October 1, 2002, the Trust filed a Current Report on Form 8-K, dated
September 30, 2002, disclosing under Item 5 that it had issued a press release
announcing that at a special meeting the Unit Holders had (a) appointed
TexasBank as the successor Trustee of the Trust and (b) approved three separate
groups of amendments to the Original Indenture.

                                        17
<PAGE>

EXHIBITS

<Table>
<Caption>
EXHIBIT
NUMBER                               NUMBER DESCRIPTION
-------                              ------------------
<C>       <C>   <S>
(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.*
   (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.*
   (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 security holders for fiscal
                year ended December 31, 2002.**
(23.1)      --  Consent of Cawley, Gillespie & Associates, Inc., reservoir
                engineer.**
</Table>

---------------

 * 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.

                                        18
<PAGE>

                                   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

                                                 /s/ LEE ANN ANDERSON
                                          --------------------------------------
                                                     Lee Ann Anderson
                                             Vice President and Trust Officer

Date: March 27, 2003

               (The Trust has no directors or executive officers)

                                        19
<PAGE>

                                 CERTIFICATION

I, Lee Ann Anderson, certify that:

     1. I have reviewed this annual report on Form 10-K of San Juan Basin
Royalty Trust, for which TexasBank acts as Trustee;

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

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

     4. I am responsible for establishing and maintaining disclosure controls
and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), or for
causing such procedures to be established and maintained, for the registrant and
I have:

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

          b) evaluated the effectiveness of the registrant's disclosure controls
     and procedures as of a date within 90 days prior to the filing date of this
     annual report (the "Evaluation Date"); and

          c) presented in this annual report my conclusions about the
     effectiveness of the disclosure controls and procedures based on my
     evaluation as of the Evaluation Date;

     5. I have disclosed, based on my most recent evaluation, to the
registrant's auditors:

          a) all significant deficiencies in the design or operation of internal
     controls which could adversely affect the registrant's ability to record,
     process, summarize and report financial data and have identified for the
     registrant's auditors any material weaknesses in internal controls; and

          b) any fraud, whether or not material, that involves persons who have
     a significant role in the registrant's internal controls; and

     6. I have indicated in this annual report whether or not there were
significant changes in internal controls or in other factors that could
significantly affect internal controls subsequent to the date of my most recent
evaluation, including any corrective actions with regard to significant
deficiencies and material weaknesses.

     In giving the certifications in paragraphs 4, 5 and 6 above, I have relied
to the extent I consider reasonable on information provided to me by Burlington
Resources Oil & Gas Company LP.

                                          TEXASBANK, AS TRUSTEE FOR THE
                                          SAN JUAN BASIN ROYALTY TRUST

                                          By:     /s/ LEE ANN ANDERSON
                                            ------------------------------------
                                                     Lee Ann Anderson
                                             Vice President and Trust Officer

Date: March 27, 2003

                                        20
<PAGE>

                                 EXHIBIT INDEX

<Table>
<Caption>
EXHIBIT
NUMBER                               NUMBER DESCRIPTION
-------                              ------------------
<C>       <C>   <S>
(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.*
   (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.*
   (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 security holders for fiscal
                year ended December 31, 2002.**
(23.1)      --  Consent of Cawley, Gillespie & Associates, Inc., reservoir
                engineer.**
</Table>

---------------

 * 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.