<PAGE>   1
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                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                   ----------

                                    FORM 10-K

(MARK ONE)

[X]             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
                        SECURITIES EXCHANGE ACT OF 1934
                  FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000,

                                       OR

[ ]           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
                     San Juan Basin Royalty Trust Indenture)

            TEXAS                                         75-6279898
  (State or other jurisdiction of                      (I.R.S. Employer
  incorporation or organization)                     Identification Number)
         BANK ONE, NA                                        76113
   CORPORATE TRUST DEPARTMENT                              (Zip Code)
        P.O. BOX 2604
       FORT WORTH, TEXAS
(Address of principal executive offices)

                                 (817) 884-4630
              (Registrant's telephone number, including area code)
           Securities registered pursuant to Section 12(b) of the Act:


                                                 NAME OF EACH EXCHANGE ON
     TITLE OF EACH CLASS                             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 [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. [X]
At March 28, 2001, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $726,165,042.

                       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 and 8; "Results
of the 4th Quarters of 2000 and 1999" at page 9; 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 10 et seq., in registrant's Annual Report to Unit
holders for fiscal year ended December 31, 2000 are incorporated herein by
reference for Item 2 (Properties), Item 3 (Legal Proceedings), 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.




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<PAGE>   2



                                     PART I

ITEM 1. BUSINESS

     The San Juan Basin Royalty Trust (the "Trust") is an express trust created
under the laws of the state of Texas by the "San Juan Basin Royalty Trust
Indenture" (the "Trust Indenture") entered into on November 3, 1980, between
Southland Royalty Company ("Southland Royalty") and The Fort Worth National
Bank, a banking association organized under the laws of the United States, as
Trustee. The Trustee is now Bank One, NA The principal office of the Trust
(sometimes referred to herein as the "Registrant") is located at 500
Throckmorton Street, Fort Worth, Texas 76102, Attention: Corporate Trust
Department (telephone number 817/884-4630).

     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 in the San Juan
Basin of northwestern New Mexico. The conveyance of this 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.

     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 which Southland Royalty
became a wholly-owned indirect subsidiary of BRI. As a result of these
transactions, El Paso Natural Gas Company ("El Paso"), Meridian Oil, Inc.
("MOI") and Meridian Oil Trading Inc. ("MOTI") also became indirect subsidiaries
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 and MOI survived and succeeded to the
ownership of all of the assets, has the rights, powers and privileges and
assumed all of the liabilities and obligations of Southland Royalty. Subsequent
to the merger, MOI changed its name to Burlington Resources Oil & Gas Company
("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 interests from which the Royalty was
carved) from the sale of the production attributable to the interests in
properties from which the Royalty was carved (the "Underlying Properties"),
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



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<PAGE>   3



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 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, to the extent it has the legal right to do so 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. As a result of the settlement of the
Litigation (as hereinafter defined), agreement was reached, among other things,
regarding the marketing of such production. See Note 5 of Notes to Financial
Statements incorporated herein by reference. 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) net revenues from the Trust
properties, plus any decrease in cash reserves previously established for
contingent liabilities and any other cash receipts of the Trust over (ii) the
expenses and payments of liabilities of the Trust plus any 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, or certificates of deposit of banks having
a capital, surplus and undivided profits in excess of $50,000,000, 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.

     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 75% net overriding royalty conveyed to the Trust was carved out of
Southland Royalty's (now BROG's) working interest and royalty interests in
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.



                                       2
<PAGE>   4



PRODUCING ACREAGE, WELLS AND DRILLING

     The Underlying Properties consist of working interests and royalty
interests 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, the Trust properties
contain 3,363 gross (975 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, 2000, 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.

     During 2000, in calculating the net proceeds to the Trust, BROG deducted
approximately $25.6 million of capital expenditures for the drilling and
completion of 45 gross (25.45 net) conventional wells, recompletion of 15 gross
(6.80 net) conventional wells, 12 gross (6.75 net) coal seam wells, 4 gross (.17
net) coal seam well recompletions, and 41 gross (.24 net) coal seam
recavitations. There were 124 gross (36.15 net) new conventional wells, 59 gross
(21.37 net) conventional well recompletions, 10 gross (2.14 net) coal seam
wells, 12 gross (1.64 net) coal seam recompletions, and 4 gross (.03 net) coal
seam recavitations in progress as of December 31, 2000.

     During 1999, in calculating the net proceeds to the Trust, BROG deducted
approximately $10.5 million of capital expenditures for the drilling and
completion of 71 gross (7.22 net) conventional wells, recompletion of four gross
(1.36 net) conventional wells, three gross (.93 net) coal seam wells, one gross
(.54 net) coal seam well recompletions, and 10 gross (.07 net) coal seam
recavitations. There were 53 gross (20.14 net) new conventional wells, 25 gross
(3.77 net) conventional well recompletions, three gross (.39 net) coal seam
wells, seven gross (.79 net) coal seam recompletions, and 38 gross (.75 net)
coal seam recavitations in progress as of December 31, 1999.

     BROG announced that the New Mexico Oil Conservation Division has approved
plans for 80-acre infill drilling of the Mesaverde formation in the San Juan
Basin. The Mesaverde formation was originally developed in the 1950's on
320-acre spacing, with infill drilling initiated in the early 1970's on 160-acre
spacing. In 1994, BROG undertook an extensive study of the Mesaverde formation.
Results indicated that downspaced drilling (infill drilling) on 80-acre spacing
could significantly increase recoverable gas reserves in this massive reservoir.
A pilot program began in 1997 and was expanded in 1998 to include two additional
areas. BROG informed the Trust that its goal in increasing capital expenditures
to $25.6 million in 2000 as compared to the $10.5 million in capital
expenditures passed through to the Trust in 1999, was to offset the natural
decline in production from the Underlying Properties. BROG announced that
natural gas production from the Underlying Properties averaged approximately 116
MMcf per day in calendar 2000 as compared to approximately 113 MMcf per day in
1999, and that production was approximately 120 MMcf per day in October of 2000.

     BROG has informed the Trust that capital expenditures for 2001 are
estimated to be $30.2 million. BROG anticipates 406 new capital projects for
2001, including the drilling of 49 new wells to be operated by BROG and 40 wells
operated by third parties. Of the new, BROG-operated wells, 42 are projected to
be conventional wells completed to the Pictured Cliffs, Mesaverde, and/or Dakota
formations, and the remaining seven are projected as coal seam gas wells to be
completed in the Fruitland Coal formation. BROG projects approximately
$17,500,000 as the cost of the new wells, with the $12,700,000 balance to be
expended in working over existing wells and in the maintenance and improvement
of production facilities.

     BROG reports that the Bureau of Land Management ("BLM") has undertaken an
environmental impact study of the entire San Juan Basin such that new drilling
activity located more than 300 feet from an existing road now requires an
additional level of regulatory approval on a well-by-well basis. Depending upon
the results of BROG's requests for approval to drill, the capital budget for
2001 may range from a low of approximately $25,000,000 to a high



                                       3
<PAGE>   5



of approximately $35,000,000, depending in large part upon the total number of
new wells for which the BLM issues approvals to drill.

     BROG indicates its budget for 2001 reflects continued, significant
development of properties in which the Trust's net overriding royalty interest
is relatively high, as well as a sustained focus on conventional formations,
including infill drilling to the Mesaverde formation, and multiple formation
completions.

OIL AND GAS PRODUCTION

     The Trust recognizes production during the month in which the related
distribution is received. Production of oil and gas and related average sales
prices attributable to the Royalty for the three years ended December 31, 2000
were as follows:


<TABLE>
<CAPTION>
                                   2000                                    1999                                  1998
                       ---------------------------------     ---------------------------------     ---------------------------------
                            OIL                GAS                OIL                GAS                OIL               GAS
                           (Bbls)             (Mcf)              (Bbls)             (Mcf)              (Bbls)             (Mcf)
                       --------------     --------------     --------------     --------------     --------------     --------------
<S>                    <C>               <C>                 <C>                <C>                <C>                <C>
Production .......             47,441         20,317,750             35,341         19,527,666             37,067         18,904,906

Average Price ....     $        24.66     $         2.99     $        14.41     $         1.78     $        13.55     $         1.75
</TABLE>


PRICING INFORMATION

     Gas produced in the San Juan Basin is sold in both interstate and
intrastate commerce. Reference is made to "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 42,220,260 Mcf during 2000.

     On September 4, 1996, the Trustee announced the settlement of the
litigation (the "Litigation") filed by the Trustee against BROG and Southland
Royalty Company. The Litigation, which was filed in the state district court of
Santa Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September
12, 1996.

     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, except for a pre-existing contract which has
     since expired, 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. 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 access
     to BROG's current gas transportation, gathering, processing and treating
     agreements with third parties through the remainder or their primary terms.

     The gas purchase contracts described in subparagraph (i), above, were
continued, by agreement of the parties until December 31, 1997. Effective
January 1, 1998, all volumes of Trust gas became subject to the terms of a
Natural Gas Sales and Purchase Contract between BROG and El Paso. That contract
was for a term of two years through and including December 31, 1999 and provided
for the sale of Trust gas at prices which will fluctuate in accordance with
published indices for gas sold in the San Juan Basin of New Mexico. BROG entered
into the contract with El Paso after soliciting and receiving competitive bids
in late 1997 from six major gas marketing firms to market and/or purchase the
Trust gas. BROG has entered into a contract dated November 10, 1999 for the sale
of all volumes of Trust gas to Duke Energy and Marketing L.L.C. ("Duke"). That
contract provides for delivery of gas at various delivery points over a



                                       4
<PAGE>   6
period commencing January 1, 2000 and ending October 31, 2001 and provides for
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. BROG is negotiating
with Duke with respect to the potential for extending the term of that contract.

     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.

     See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 2000 for further discussion of
this settlement and its impact on the Trust.

OIL AND GAS RESERVES

     The following are definitions adopted by the Securities and Exchange
Commission ("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 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, 1998, 1999 and 2000 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1997 to
December 31, 2000 (in thousands):

<TABLE>
<CAPTION>
                                                        CRUDE         NATURAL
                                                         OIL            GAS
                                                        (Bbls)         (Mcf)
                                                       --------      --------
<S>                                                    <C>           <C>
Reserves as of December 31, 1997 .................          559       203,339
                                                       --------      --------
Revisions of previous estimates ..................         (195)      (26,204)
Extensions, discoveries and other additions ......            6         5,201
Production .......................................          (37)      (18,905)
                                                       --------      --------

Reserves as of December 31, 1998 .................          333       163,431
                                                       --------      --------
Revisions of previous estimates ..................          120        53,936
Extensions, discoveries and other additions ......           29        14,498
Production .......................................          (32)      (17,650)
                                                       --------      --------
Reserves as of December 31, 1999 .................          450       214,215
                                                       --------      --------
Revisions of previous estimates ..................          199        72,803
Extensions, discoveries and other additions ......           80        36,207
Production .......................................          (47)      (20,318)
                                                       --------      --------
Reserves as of December 31, 2000 .................          682       302,907
                                                       ========      ========
</TABLE>



                                       5
<PAGE>   7

Estimated quantities of proved developed reserves of crude oil and natural gas
as of December 31, 2000, 1999 and 1998 were as follows (in thousands):



<TABLE>
<CAPTION>
                                                                                 CRUDE       NATURAL
                                                                                  OIL          GAS
                                                                                 (Bbls)       (Mcf)
                                                                                 -------     -------
<S>                                                                              <C>         <C>
2000 .......................................................................         624     277,459
1999........................................................................         422     201,891
1998 .......................................................................         328     159,454
</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 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 2000, 1999 and 1998 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>
                                                                       2000            1999         1998
                                                                     --------        --------     --------
<S>                                                                   <C>            <C>           <C>
Balance, January 1 ............................................      $229,721        $144,472      $213,504
Revisions of prior-year estimates, change in prices
   and other ..................................................       530,811          90,172       (63,731)
Extensions, discoveries and other additions ...................        94,753          13,257         3,667
Accretion of discount .........................................        22,972          14,447        21,350
Royalty income ................................................       (60,045)        (32,627)      (30,318)
                                                                                     --------      --------
Balance, December 31 ..........................................      $818,212        $229,721      $144,472
                                                                     ========        ========      ========
</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.



                                       6
<PAGE>   8



     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. The upward revision is primarily due to
significantly higher gas prices in December 2000.

     December average prices of $2.39 per Mcf of conventional gas, $1.49 per Mcf
of coal seam gas and $22.30 per Bbl of oil were used at December 31, 1999, in
determining future net revenue. The upward revision is primarily due to
significantly higher gas prices in December 1999.

     December average prices of $1.82 per Mcf of conventional gas, $1.30 per Mcf
of coal seam gas and $8.60 per Bbl of oil were used at December 31, 1998, in
determining future net revenue. The downward revision is primarily due to
significantly lower oil and gas prices in December 1998 as compared to December
1997.

     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, 2000, 1999 and 1998 (in thousands except amounts per Unit):


<TABLE>
<CAPTION>
                                        2000                              1999                            1998
                                -------------------------     --------------------------    ------------------------
                                 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 ..............     $1,580,837     $  818,212     $  408,609     $  229,721     $  241,206     $  144,472
Proved Developed ..........     $1,445,557     $  752,825     $  383,356     $  219,677     $  234,973     $  142,095
Total Proved Per Unit .....     $    33.92     $    17.55     $     8.77     $     4.93     $     5.18     $     3.10
</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 Federal Energy Regulatory Commission (the "FERC") is primarily
responsible for federal regulation of natural gas. The interstate transportation
and sale for resale of natural gas is subject to federal governmental
regulation, including regulation of transportation and storage tariffs and
various other matters, by the FERC. The Natural Gas Wellhead Decontrol Act of
1989 ("Decontrol Act") terminated federal price controls on wellhead sales of
domestic natural gas on January 1, 1993. Consequently, sales of natural gas may
be made at market prices, subject to applicable contract provisions. The FERC's
jurisdiction over natural gas transportation and storage was unaffected by the
Decontrol Act.



                                       7
<PAGE>   9



     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 the FERC from 1985 to the present
that affect the economics of natural gas production, transportation, and sales.
In addition, the 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 the 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, the 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 the FERC and Congress will continue.

     Sales of crude oil, condensate and gas liquids are not currently regulated
and are made at market prices. Effective as of January 1, 1995, the FERC
implemented regulations establishing an indexing system for transportation rates
for oil that could increase the cost of transporting oil to the purchaser or
reduce wellhead prices for crude oil.

     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. For 2000, this tax credit is estimated to
be approximately $1.06 per MMBtu, the actual amount to be determined by the
Treasury Department no later than April 1, 2001. 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 coal seam volumes produced from Trust 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 the FERC. The
FERC's certification authority expired effective January 1, 1993. However, on
July 14, 2000, the 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.

     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.



                                       8
<PAGE>   10



ITEM 3. LEGAL PROCEEDINGS

     On September 4, 1996, the Trustee announced the settlement of the
Litigation filed by the Trustee against BROG and Southland Royalty Company. The
Litigation, which was filed in the state district court of Santa Fe County, New
Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996.

     The claims asserted on behalf of the Trust in the Litigation included
breach of contract, breach of the covenant of good faith and fair dealing,
breach of express good faith duty, constructive fraud, unjust enrichment, prima
facie tort, intentional interference with contract and conspiracy. The relief
sought included compensatory and punitive damages, an accounting and an
injunction relating to marketing the production from the Underlying Properties.
BROG has denied and continues to deny the allegations made against it in the
Litigation, but the parties have agreed to settle the Litigation as outlined
herein.

     BROG agreed (i) to pay $19,750,000 in cash plus interest earnings thereon
from September 5, 1996, in settlement of underpayment of royalty claims of the
Trust; and (ii) commencing in 1997, to credit the Trust with $250,000 per year
for five years as an offset against lease operating expenses chargeable to the
Trust for purposes of the calculation of net proceeds payable to the Trust. BROG
also agreed to make certain adjustments that represent cost reductions favorable
to the Trust in the ongoing charges for coal seam gas gathering and treating on
BROG's Val Verde system. Additionally, the Trustee and BROG established a formal
protocol intended to provide the Trustee and its representatives improved access
to BROG's books and records applicable to the Underlying Properties.

     Agreement was also reached regarding marketing arrangements for the sale of
Trust gas, oil and natural gas liquids products going forward as more
particularly described in "Pricing Information" under Item 2. Properties herein.

     The $19,822,005 (or $.425285 per unit of beneficial interest) was paid to
the Trust on September 30, 1996 and distributed on October 15, 1996, to
unitholders of record as of September 30, 1996, (the "Record Date"). The
distribution was taxable to unit holders as of such Record Date. This
distribution was in addition to the regular monthly distribution on October 15,
1996.

     A lawsuit was commenced on September 1, 1995 against BROG by certain
royalty and overriding royalty owners on behalf of those persons similarly
situated. This case is one of six virtually identical class actions filed
against New Mexico gas producers. All such cases have been consolidated in the
First Judicial District of Santa Fe County, New Mexico where the case is styled
San Juan 1990-A, L.P., et al. v. El Paso Production Co., et al. The plaintiffs
allege that they and members of the proposed class have been underpaid for
royalties and overriding royalties. BROG has now informed the Trust that this
litigation is unlikely to have any direct effect on royalty income payable to
the Trust.

     In addition, 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 alleges that
additional royalties are due on production from federal and Indian leases in the
State of New Mexico on properties that are burdened by the Royalty. BROG filed
its statement of reasons in June 1997 thereby contesting whether the royalties
are payable as claimed. BROG has informed the Trust that the administrative
claim is in the appeal process. If the MMS claim is successful, royalty income
received by the Trust could decrease. BROG reports that the MMS and BROG have
entered into settlement discussions in an attempt to settle this issue together
with other take-or-pay claims made by the MMS, but there has been no indication
of the likelihood of success in resolving the claim or when the negotiations are
to be completed.

     MMS has notified BROG of underpaid royalty related to coal seam gas
including inappropriate deductions for costs to separate carbon dioxide from the
gas. BROG has continued to calculate and pay royalties using deductions the MMS
is attempting to disallow. The Company has appealed the MMS Demand Letter dated
October 28, 1996. There is a tolling agreement with the MMS while settlement
negotiations are attempted.



                                       9
<PAGE>   11



     An administrative claim was initiated on June 10, 1998 by the MMS against
BROG related to production from lands on the Jicarilla Apache Indian
Reservation. The claim alleges that additional royalties are due based upon the
"major portion" valuation clause contained in the Jicarilla leases. This clause
contemplates royalty value to be calculated on "the highest price paid or
offered at the time of production for the major portion of oil of the same
gravity, and gas, and/or natural gasoline, and/or all other hydrocarbon
substances produced and sold from the field where the leased lands are
situated." BROG indicates that producers do not have access to prices received
by other producers in a field, so a "major portion" calculation must be done by
the MMS. BROG filed its statement of reasons in June 1999 thereby contesting
whether the royalties are payable as claimed. The administrative claim is in the
appeal process. If the MMS claim is successful, royalty income received by the
Trust could decrease.

     BROG has successfully negotiated with the State of New Mexico for a tax
refund based upon a claim for reimbursement of compression costs used in
calculating wellhead values. BROG has obtained the approval of the Attorney
General of New Mexico of a settlement in the amount of $4,200,000, and in
December 2000 passed through to the Trust $263,607 of the settlement proceeds in
the form of a reduction in production costs. The Trust's consultants are in
communication with BROG and will review the allocation of settlement proceeds.

     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 subject properties. The remainder of the
imbalance is to be addressed through volume adjustments whereby the Trust's net
overriding royalty interest will be applied to 50% of the overproduced parties'
interest, on a monthly basis, until the imbalance is corrected. The Trust is 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.
Those adjustments will be monitored by the Trust's consultants.

     For additional information concerning legal proceedings, Note 5 of the
Notes to Financial Statements at pages 14 and 15 of the Trust's Annual Report to
security holders for the year ended December 31, 2000 are herein incorporated by
reference.

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, 2000.

                                     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, 2000,
is herein incorporated by reference.



                                       10
<PAGE>   12



ITEM 6. SELECTED FINANCIAL DATA


<TABLE>
<CAPTION>
                                                        For the Year Ended December 31,
                                   ---------------------------------------------------------------------------
                                      2000             1999            1998           1997            1996
                                   -----------     -----------     -----------     -----------     -----------
<S>                                <C>             <C>             <C>             <C>             <C>
Royalty income ...............     $60,044,773     $32,626,966     $30,317,860     $49,497,479     $41,236,424(1)
Distributable income .........      59,188,932      31,795,667      29,598,402      48,648,930      37,803,167
Distributable income per
   Unit ......................        1.269909        0.682182        0.635039        1.043770        0.811072
Distributions per Unit .......        1.269909        0.682182        0.635039        1.043770        0.811072
Total assets, December 31 ....      47,659,746      49,048,652      53,753,582      61,231,280      65,935,976
</TABLE>

----------

(1)  The royalty income distributions for 1996 include material payments
     received in settlement of litigation as more particularly described under
     "Item 2. Properties" herein.

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

     The "Trustee's Discussion and Analysis" and "Results of the 4th Quarters of
2000 and 1999" at pages 7 through 9 of the Trust's Annual Report to
securityholders for the year ended December 31, 2000, are herein incorporated by
reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

     The Trust has not entered into derivative financial instruments, derivative
commodity instruments or other similar instruments during 2000. As discussed in
Item 2. Properties -- Pricing Information, the Trust does not market the Trust
gas, oil and/or natural gas liquids. 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 10 et
seq., of the Trust's Annual Report to security holders for the year ended
December 31, 2000, are herein incorporated by reference.

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

     None.



                                       11
<PAGE>   13



                                    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 or executive officers. During the year ended
December 31, 2000, the Trustee received total remuneration as follows:

<TABLE>
<CAPTION>
  NAME OF INDIVIDUAL OR NUMBER OF                                                   CAPACITIES IN WHICH              CASH
        PERSONS IN GROUP                                                                  SERVED                 COMPENSATION
  --------------------------------                                                 -------------------          ------------
<S>                                                                                <C>                          <C>
  Bank One, NA..........................................................                  Trustee               $  98,512.40(1)
</TABLE>

----------

(1)  Under the Trust Indenture, the Trustee is entitled to an administrative fee
     for its administrative services, preparation of quarterly and annual
     statements with attention to tax and legal matters 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. The administrative fee is subject to reduction by a credit
     for funds provision.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

     (a) Security Ownership of Certain Beneficial Owners. The following table
sets forth, as of December 31, 2000, 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) .............................     15,594,000 Units                 33.5%
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

Arnhold and S. Bleichroeder, Inc.(3) ...............      2,988,300 Units                  6.4%
Arnhold and S. Bleichroeder Advisers, Inc.
1345 Avenue of the Americas
New York, New York 10105

McMorgan and Company(4) ............................      3,000,000 Units                  6.4%
1 Bush Street, Suite 800
San Francisco, CA 94104

Capital Group International, Inc.(5) ...............      2,635,200 Units                  5.7%
Capital Guardian Trust Company
11100 Santa Monica Blvd
Los Angeles, CA 90025
</TABLE>

----------

(1)  This information was provided to the Trust on Amendment Number 19 to
     Schedule 13D, dated April 14, 2000, as filed with the Securities and
     Exchange Commission (the "SEC") by Alpine Capital L.P. ("Alpine"), which
     indicated that these Units were beneficially owned by Alpine. The Amendment
     Number 19 to Schedule 13D may be reviewed for more detailed information
     concerning the matters summarized herein.



                                       12
<PAGE>   14



(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 4 to
     Schedule 13G, dated February 13, 2001. Arnhold and S. Bleichroeder, Inc.
     and Arnhold and S. Bleichroeder Advisers, Inc. report shared voting power
     over 2,988,300 Units and shared dispositive power over 2,988,300 Units. The
     Amendment Number 4 to Schedule 13G filed with the SEC 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.

(5)  This information was provided to the Trust in Amendment Number 3 to
     Schedule 13G dated December 29, 2000. Capital Group International, Inc. and
     Capital Guardian Trust Company each reported sole voting power over
     1,977,800 Units and sole dispositive power over 2,635,200 Units. The
     Amendment Number 3 to Schedule 13G may be reviewed for more detailed
     information concerning the matters summarized herein.


     (b) Security Ownership of Management. In various fiduciary capacities, Bank
One, NA owned, as of December 31, 2000, an aggregate of 32,652 Units with no
right to vote any of these Units. Bank One, NA disclaims any beneficial interest
in these Units. The number of Units reflected in this paragraph includes Units
held by all branches of Bank One, NA.

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, 2000 and
Item 12(b) for information concerning Units owned by Bank One, NA in various
fiduciary capacities.



                                       13
<PAGE>   15


                                     PART IV

ITEM 14. 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, 2000:

                    Independent Auditors' Report
                    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.



<TABLE>
<CAPTION>
EXHIBIT
NUMBER       DESCRIPTION
------       -----------
<S>          <C>
(4)(a)  --   San Juan Basin Royalty Trust Indenture, dated November 3, 1980,
             between Southland Royalty Company and The Fort Worth National Bank
             (now Bank One, NA), as Trustee, heretofore filed as Exhibit 4(a) to
             the Trust's Annual Report on Form 10-K to the SEC for the fiscal
             year ended December 31, 1980, is incorporated herein by reference.*

   (b)  --   Net Overriding Royalty Conveyance from Southland Royalty Company to
             the Forth Worth National Bank (now Bank One, NA), as Trustee, dated
             November 3, 1980 (without Schedules), heretofore filed as Exhibit
             4(b) to the Trust's Annual Report on Form 10-K to the SEC for the
             fiscal year ended December 31, 1980, is incorporated herein by
             reference.*

(13)    --   Registrant's Annual Report to security holders for fiscal year
             ended December 31, 2000.**

(23)    --   Consent of Cawley, Gillespie & Associates, Inc., reservoir
             engineer.**
</TABLE>

----------

*    A copy of this Exhibit is available to any Unit holder, at the actual cost
     of reproduction, upon written request to the Trustee, Bank One, NA, P.O.
     Box 2604, Fort Worth, Texas 76113.

**   Filed herewith.


REPORTS ON FORM 8-K

     On October 27, 2000, a report on Form 8-K was filed with the Securities and
Exchange Commission by the Trust, announcing the upward adjustment of
anticipated capital expenses of the Trust for fiscal year ended December 31,
2000.




                                       14
<PAGE>   16



                                    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.

                                       BANK ONE, NA
                                       TRUSTEE OF THE SAN JUAN BASIN
                                       ROYALTY TRUST


                                       By:/s/ LEE ANN ANDERSON
                                          --------------------------------------
                                                 (Lee Ann Anderson)
                                                  Vice President

Date: March 30, 2001


               (The Trust has no directors or executive officers)



                                       15
<PAGE>   17



                                  EXHIBIT INDEX



<TABLE>
<CAPTION>
EXHIBIT
NUMBER       DESCRIPTION
------       -----------
<S>          <C>
(4)(a)  --   San Juan Basin Royalty Trust Indenture, dated November 3, 1980,
             between Southland Royalty Company and The Fort Worth National Bank
             (now Bank One, NA), as Trustee, heretofore filed as Exhibit 4(a) to
             the Trust's Annual Report on Form 10-K to the SEC for the fiscal
             year ended December 31, 1980, is incorporated herein by reference.*

   (b)  --   Net Overriding Royalty Conveyance from Southland Royalty Company to
             the Forth Worth National Bank (now Bank One, NA), as Trustee, dated
             November 3, 1980 (without Schedules), heretofore filed as Exhibit
             4(b) to the Trust's Annual Report on Form 10-K to the SEC for the
             fiscal year ended December 31, 1980, is incorporated herein by
             reference.*

(13)    --   Registrant's Annual Report to security holders for fiscal year
             ended December 31, 2000.**

(23)    --   Consent of Cawley, Gillespie & Associates, Inc., reservoir
             engineer.**
</TABLE>

----------

*    A copy of this Exhibit is available to any Unit holder, at the actual cost
     of reproduction, upon written request to the Trustee, Bank One, NA, P.O.
     Box 2604, Fort Worth, Texas 76113.

**   Filed herewith.




                                       16