<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, 1999,

                                       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, TEXAS, N.A.                               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 April 12, 2000, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $463,174,910.

                       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 1998 and 1997" 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, 1999 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, Texas, N.A. 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 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


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<PAGE>   3



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 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 recovered 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.

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 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 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


                                        2

<PAGE>   4
received from the Trust's independent petroleum engineers, the Trust properties
contain 3,204 gross (897 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, 1999, 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 1999, BROG incurred approximately $10.5 million of capital
expenditures for the drilling and completion of 71 gross (7.22 net) conventional
wells, recompletion of 4 gross (1.36 net) conventional wells, drilling and
completion of 3 gross (.93 net) coal seam wells, 1 gross (.54 net) coal seam
well recompletion, 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, 3 gross (.39 net) coal seam wells, 7 gross (.79 net) coal seam
recompletions, and 38 gross (.75 net) coal seam recavitations in progress as of
December 31, 1999.

         During 1998, BROG incurred approximately $12.8 million of capital
expenditures for the drilling and completion of 36 gross (11.89 net)
conventional wells, recompletion of 25 gross (13.8 net) conventional wells, two
gross (.08 net) coal seam well recompletions, and 37 gross (2.28 net) coal seam
recavitations. There were 17 gross (1.46 net) new conventional wells, one gross
(.05 net) coal seam recompletion, and three gross (.12 net) coal seam
recavitations in progress as of December 31, 1998.

         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.

         The Trust has been advised that capital expenses for 2000 are projected
to be approximately $20.5 million. Approximately 95% of that amount will be
attributable to conventional projects. Of the 400 planned projects, 57 will be
conventional new drill locations at a cost of approximately $13.7 million, 99
will be attributable to workovers at a cost of $5.2 million, and 244 of the
projects will be miscellaneous facilities projects at a cost of $1.6 million. Of
the 57 new drilling projects planned for 2000, 21 are on properties in which
BROG owns 100% of the working interest, so that the Trust's share of the planned
capital expenditures is increased as compared to wells in which BROG owns only a
partial working interest.

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, 1999
were as follows:

<TABLE>
<CAPTION>

                                1999                      1998                      1997
                       -----------------------   -----------------------   -----------------------
                           Oil         Gas          Oil          Gas          Oil          Gas
                         (Bbls)       (Mcf)        (Bbls)       (Mcf)        (Bbls)       (Mcf)
                       ----------   ----------   ----------   ----------   ----------   ----------
<S>                    <C>          <C>          <C>          <C>          <C>          <C>
Production .........       35,341   19,527,666       37,067   18,904,906       50,860   24,236,419
Average Price ......   $    14.41   $     1.78   $    13.55   $     1.75   $    19.35   $     2.21
</TABLE>



                                        3

<PAGE>   5

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 39,940,175 Mcf during 1999.

         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
is for a term of two years through and including December 31, 1999 and provides
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. That contract
provides for delivery of gas at various delivery points over a 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.

         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, 1998 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

                                        4

<PAGE>   6
         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, 1997, 1998 and 1999 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1996 to
December 31, 1999 (in thousands):

<TABLE>
<CAPTION>

                                                      CRUDE       NATURAL
                                                       OIL          GAS
                                                      (Bbls)       (Mcf)
                                                     --------    --------

<S>                                                  <C>         <C>
Reserves as of December 31, 1996 .................        657     245,995
Revisions of previous estimates ..................        (81)    (25,734)
Extensions, discoveries and other additions ......         34       7,314
Production .......................................        (51)    (24,236)
                                                     --------    --------
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
                                                     ========    ========
</TABLE>



Estimated quantities of proved developed reserves of crude oil and natural gas
as of December 31, 1999, 1998 and 1997 were as follows (in thousands):

<TABLE>
<CAPTION>

                                                        CRUDE       NATURAL
                                                         OIL          GAS
                                                        (Bbls)       (Mcf)
                                                        ------      -------

<S>                                                  <C>          <C>
1999 .............................................       422        201,891
1998 .............................................       328        159,454
1997 .............................................       547        199,753
</TABLE>

                                        5

<PAGE>   7
         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 1999, 1998 and 1997 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>

                                                                   1999          1998           1997
                                                               -----------   -----------    -----------

<S>                                                            <C>           <C>            <C>
Balance, January 1 .........................................   $   144,472   $   213,504    $   439,037
Revisions of prior-year estimates, change in prices
   and other ...............................................        90,172       (63,731)      (227,855)
Extensions, discoveries and other additions ................        13,257         3,667          7,915
Accretion of discount ......................................        14,447        21,350         43,904
Royalty income .............................................       (32,627)      (30,318)       (49,497)
                                                               -----------   -----------    -----------
Balance, December 31 .......................................   $   229,721   $   144,472    $   213,504
                                                               ===========   ===========    ===========
</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 $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.

         December average prices of $2.21 per Mcf of conventional gas, $1.55 per
Mcf of coal seam gas and $15.97 per Bbl of oil were used at December 31, 1997,
in determining future net revenue. The downward revision is primarily due to
significantly lower gas prices in December 1997 as compared to December 1996.


                                        6

<PAGE>   8
         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, 1999, 1998 and 1997 (in thousands except amounts per
Unit):

<TABLE>
<CAPTION>

                                     1999                   1998                     1997
                            ---------------------   ---------------------   ---------------------
                            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 ............   $ 408,609   $ 229,721   $ 241,205   $ 144,472   $ 372,830   $ 213,504
Proved Developed ........   $ 383,356   $ 219,677   $ 234,973   $ 142,095   $ 365,509   $ 211,580
Total Proved Per Unit ...   $    8.77   $    4.93   $    5.18   $    3.10   $    8.00   $    4.58
</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.

         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

                                        7

<PAGE>   9
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 1999, this tax credit will be
approximately $1.04 per MMBtu. 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. Many producers
believe that wells meeting the certification requirements are eligible for the
Section 29 credit regardless of the FERC certification. However, this position
is not in accordance with the IRS position or the decisions of the Tenth Circuit
Court or the Tax Court. The courts may hear other cases regarding this matter
and it is not possible to predict the likely outcome. In the event the IRS
position is ultimately upheld, the ability of the Unit holders to utilize
allocated Section 29 credits in full could be questioned. But on December 23,
1999, a petition was filed with the FERC by a coalition of energy producers
seeking reinstatement of the certification process. By letter dated January 14,
2000, the U.S. Department of Energy expressed its support of that petition and
on January 27, 2000 the FERC issued notice of proposed rulemaking by which its
regulations would be amended to reinstate certain regulations involving well
category determinations for Section 29 tax credits for certain well
recompletions commenced after January 1, 1993. It is not yet possible to predict
the likely outcome of this rulemaking process.

         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. The suit involves properties that are burdened by the Trust. 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 Company and Meridian Oil Inc. The plaintiffs allege
that they and members of the proposed class have been underpaid for royalties
and overriding royalties. The plaintiffs have sought to certify the actions as
class actions and seek monetary damages. The court has denied class
certification, but the plaintiffs have renewed their request for class
certification. Discovery in this matter is closed. BROG anticipates summary
judgment proceedings to occur in the summer of 2000. Because of the pending
nature of the litigation, exposure to the Trust from this suit cannot be
quantified. However, if the plaintiffs who have interests in properties that are
burdened by the Trust are successful, royalty income received by the Trust could
decrease.

         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 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. In June 1997 BROG
filed its statement of reasons 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.

                                        9

<PAGE>   11



         BROG is in negotiations 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 payment has been
received. BROG has not informed the Trust of the proportion of the settlement
proceeds which will be attributable to the Trust.

         In February 1999, the Trust's auditors notified the Trust of an
apparent gas imbalance. A gas imbalance occurs where more than one party is
entitled to the economic benefit of the production of natural gas, but the gas
is sold for the account of less than all of the parties. The resulting imbalance
may be corrected by various means including a cash settlement and/or a volume
adjustment whereby an increased percentage of future production is sold for the
account of the underproduced party or parties. The Trust's auditors suggested
that the subject imbalance might relate to the acquisition by BROG's
predecessor, Southland Royalty, of mineral properties which had been operated
under a Joint Operating Agreement between Southland Royalty and Unicon, the
seller of the properties. The Trust made inquiry of BROG concerning the
imbalance and BROG agreed to investigate the records. The Trustee met with BROG
representatives in June 1999 to discuss the investigation, and by correspondence
of September 24, 1999, BROG reported that the imbalance probably related to
problems experienced in the 1980's and early 1990's by Southland Royalty and
Unicon in their dealings with Public Service Company of New Mexico. BROG
reported that Unicon was flowing gas to its account while Southland Royalty was
not producing and that this created a gas imbalance. The imbalance was
addressed, as between Southland Royalty and Unicon, by a reduction in the total
purchase price for Unicon assets acquired by Southland Royalty in June 1990.
However, there was no payment made to the Trust at the time of that acquisition.

         BROG proposes to address the imbalance with the Trust based upon the
terms of a Gas Balancing Agreement it indicates was in place between Southland
Royalty and Unicon, in connection with the Joint Operating Agreement applicable
to the subject properties and has offered $3,100,000 as a cash settlement.
The Trust is considering the appropriateness of this proposed means of
resolution and this offer and is consulting with its advisors. No assurance can
be given as to when and how this issue will be resolved.

         For additional information concerning legal proceedings, Note 5 of the
Notes to Financial Statements on pages 14 and 15 of the Trust's Annual Report
to security holders for the year ended December 31, 1999 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, 1999.
                                     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, 1999,
is herein incorporated by reference.

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>

                                                           For the Year Ended December 31,
                                 --------------------------------------------------------------------------------
                                      1999            1998            1997            1996               1995
                                 -------------   -------------   -------------   -------------      -------------

<S>                              <C>             <C>             <C>             <C>                <C>
Royalty income ...............   $  32,626,966   $  30,317,860   $  49,497,479   $  41,236,424(1)   $  15,156,292
Distributable income .........      31,795,667      29,598,402      48,648,930      37,803,167         13,790,101
Distributable income per
   Unit ......................        0.682182        0.635039        1.043770        0.811072           0.295867
Distributions per Unit .......        0.682182        0.635039        1.043770        0.811072           0.295867
Total assets, December 31 ....      49,048,652      53,753,582      61,231,280      65,935,976         70,554,982
</TABLE>


                                       10
<PAGE>   12

----------

(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 1999 and 1998" at pages 7 through 9 of the Trust's Annual Report
to securityholders for the year ended December 31, 1999, 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 1999. 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, 1999, 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, 1999, 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, Texas, N.A.................................            Trustee            $  88,163(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, 1999, 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)..................................  15,049,200 Units               32.3%
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)....................  3,250,000 Units                 6.9%
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
</TABLE>

----------

(1)      This information was provided to the Trust on Amendment Number 18 to
         Schedule 13D, dated March 15, 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 18 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 15, 2000. Arnhold and S. Bleichroeder,
         Inc. and Arnhold and S. Bleichroeder Advisers, Inc. report shared
         voting power over 3,250,000 Units and shared dispositive power over
         3,250,000 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.

         (b) Security Ownership of Management. In various fiduciary capacities,
Bank One, Texas, N.A. owned, as of December 31, 1999, an aggregate of 42,472
Units with the sole right to vote 34,672 of these Units and no right to vote
7,800 of these Units. Bank One, Texas, N.A. disclaims any beneficial interest
in these Units. The number of Units reflected in this paragraph includes Units
held by all branches of Bank One, Texas, N.A.

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, 1999 and
Item 12(b) for information concerning Units owned by Bank One, Texas, N.A. 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, 1999:

                  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.


 EXHIBIT
  NUMBER                                DESCRIPTION
 -------                                -----------

(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, Texas, N.A.), 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, Texas,
                  N.A.), 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, 1999.**

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

  (27)            -- Financial Data Schedule.**

----------

*        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,
         Texas, N.A., P.O. Box 2604, Fort Worth, Texas 76113.

**       Filed herewith.

REPORTS ON FORM 8-K

         During the last quarter of the Trust fiscal year ended December 31,
1999, no reports on Form 8-K were filed with the Securities and Exchange
Commission by the Trust.

                                       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, TEXAS, N.A.
                                           TRUSTEE OF THE SAN JUAN BASIN
                                           ROYALTY TRUST

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

Date: April 14, 2000

               (The Trust has no directors or executive officers)




<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, Texas, N.A.), 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, Texas,
                  N.A.), 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, 1999.**

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

  (27)            -- Financial Data Schedule.**
</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,
         Texas, N.A., P.O. Box 2604, Fort Worth, Texas 76113.

**       Filed herewith.