<PAGE>

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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

                                (Fee Required)

                For the fiscal year ended December 31, 1996, or

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

                               (No Fee Required)

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)
                                                          76113
           BANK ONE, TEXAS, NA                         (Zip Code)
             TRUST DEPARTMENT
              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:

           TITLE OF EACH CLASS            NAME OF EACH EXCHANGE ON   WHICH
     UNITS OF BENEFICIAL INTEREST                   REGISTERED

                                               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 25, 1997, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $367,044,269.

                      DOCUMENTS INCORPORATED BY REFERENCE

  "Units of Beneficial Interest" at page 2; "Description of the Properties" at
page 4; "Trustee's Discussion and Analysis" at pages 6 and 7; "Results of the
4th Quarters of 1996 and 1995" 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 security holders for fiscal year ended December 31, 1996 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>

                                    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, NA. The principal office of the
Trust (sometimes referred to herein as the "Registrant") is located at 500
Throckmorton Street, Suite 704, Fort Worth, Texas 76102 (telephone number
817/844-4630).

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

  The 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.

  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, subject to certain adjustments. "Production
costs" means, generally, costs incurred on an accrual basis by BROG in
operating its properties and interests out of which the Royalty was carved,
including both capital and non-capital costs. For example, these costs include
development drilling, production and processing costs, applicable taxes, and
operating charges. If production costs exceed gross proceeds in any month, the
excess is recovered out of future gross proceeds prior to the making of
further payment to the Trust, but the Trust is not otherwise liable for any
production costs or other costs or liabilities attributable to these
properties and interests or the minerals produced therefrom. If at any time
the Trust receives more than the amount due under the Royalty, it shall not be
obligated to return such overpayment, but the amounts payable to it for any
subsequent period shall be reduced by such amount, plus interest, at a rate
specified in the conveyance.

                                       1
<PAGE>

  Certain of the properties and interests out of which the Royalty was carved
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 and
interests, either under existing sales contracts or under future arrangements
at the best prices and on the best terms it shall deem reasonable 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 properties from which the Royalty
was carved.

  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 properties from which the Royalty was carved 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 working interest and royalty interests in the San Juan
Basin in northwestern New Mexico. References below to "net" wells and acres
are to the interests of BROG (from which the Royalty was carved) in the
"gross" wells and acres.

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

PRODUCING ACREAGE, WELLS AND DRILLING

  BROG's working interests and royalty interests in the San Juan Basin consist
of 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and
Sandoval counties. Based upon information received from the Trust's
independent petroleum engineers, the Trust properties contain 3,180 gross (960
net) economic wells, including dual completions. Production from conventional
gas wells is primarily from the Pictured Cliffs, Mesa Verde and Dakota
formations. During 1988, Southland Royalty began development of coal seam
reserves in the Fruitland 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, 1996, is
herein incorporated by reference.

                                       2
<PAGE>

  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 1996, there were 14 gross (1.50 net) conventional wells completed.
There was 1 gross (.05 net) coal seam well and 17 gross (1.96 net)
conventional wells in progress at December 31, 1996. There were 4 gross (.16
net) conventional wells recompleted as coal seam wells, 17 gross (5.63 net)
coal seam wells recavitated and 9 gross (5.93 net) conventional wells
recompleted through December 31, 1996. During 1995, there were 24 gross (6.36
net) wells completed including 5 gross (2.54 net) coal seam wells. There were
4 gross (1.89 net) coal seam wells and 7 gross (2.24 net) conventional wells
in progress at December 31, 1995. There were 24 gross (11.41 net) coal seam
wells and 38 gross (8.61 net) conventional wells recompleted through December
31, 1995. During 1994, there were 21 gross (6.76 net) wells completed
including 8 gross (4.80 net) coal seam wells. There were 4 gross (2.55 net)
coal seam wells and 23 gross (7.69 net) conventional wells in progress at
December 31, 1994. There were 17 gross (10.57 net) coal seam wells and 44
gross (12.96 net) conventional wells recompleted through December 31, 1994.

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, 1996
were as follows:

<TABLE>
<CAPTION>
                                 1996              1995               1994
                           ----------------- ------------------ ------------------
                            OIL      GAS      OIL       GAS      OIL       GAS
                           (BBLS)    (MCF)   (BBLS)     (MCF)   (BBLS)     (MCF)
                           ------ ---------- ------  ---------- ------  ----------
<S>                        <C>    <C>        <C>     <C>        <C>     <C>
Production................ 36,792 17,927,785 29,424  13,331,758 36,769  15,459,542
Average Price............. $19.64      $1.30 $14.43       $1.25 $13.09       $1.66
</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 40,738,422 Mcf during
1996.

  Prior to 1985, sales contracts with El Paso, Sunterra Gas Gathering Company,
formerly Southern Union Gathering Company ("Sunterra"), and Northwest Pipeline
Company ("Northwest") generally provided for payment of the maximum lawful
prices permitted under the Natural Gas Policy Act of 1978 ("NGPA"). Sunterra
is a subsidiary of Public Service Company of New Mexico ("PNM").

  In 1985, Sunterra sold its gas gathering, transportation and distribution
facilities in New Mexico and its rights as purchaser under its San Juan Basin
gas contracts to PNM. Under such contracts, gas prices were to be redetermined
annually on April 1 to an average of the highest price levels being paid in
New Mexico. Also in 1985, PNM announced its intention to attempt to
renegotiate the gas contracts with gas producers in the San Juan Basin,
including Southland Royalty, with its objective being to reduce the overall
price for such gas. During the course of these negotiations PNM unilaterally
reduced the price paid for gas sales below the level required by the gas
contracts.

  In May 1988, PNM filed suit in the United States District Court in New
Mexico seeking (i) a declaratory judgment that PNM had no prior liability for
gas purchased at prices below the contract prices and (ii) a permanent
injunction prohibiting future claims against PNM for gas purchases at prices
below the contract prices. PNM claimed the pricing provisions were the result
of a conspiracy in violation of antitrust laws. Southland Royalty counter-
claimed against PNM alleging breach of both the pricing provisions and the
minimum take requirements of the gas purchase contracts. In June 1988,
Southland Royalty filed a separate breach of contract

                                       3
<PAGE>

suit in a State District Court in Harris County, Texas on these same claims
against PNM alleging damages in excess of $40 million. During 1988, both El
Paso and Northwest abandoned the Natural Gas Act ("NGA") service obligation to
purchase gas in accordance with Federal Energy Regulatory Commission ("FERC")
Order 490 and 490-A.

  Southland Royalty informed the Trust that effective March 1, 1990 a
settlement of this litigation was reached. Under the terms of the settlement
agreement, Southland Royalty released all claims that it had against PNM,
Sunterra and Gas Company of New Mexico (a division of PNM) ("Gas Company")
under the intrastate gas purchase contracts, as well as claims it held on gas
sold pursuant to the interstate contracts discussed previously. PNM and
Sunterra agreed to pay Southland Royalty $54.5 million in installments. An
initial payment of $18,166,000 was paid in connection with the execution of
the settlement agreement. The second payment of $18,167,000 was paid on March
1, 1991. The remaining balance of $18,167,000 was paid on March 2, 1992 plus
interest of $1,635,300.

  Southland Royalty distributed to the Trust 75% (the amount of its net
overriding royalty interest) of the $49,435,300 in cash received in settlement
that it attributed to past and future pricing claims under the intrastate and
interstate gas purchase contracts, less amounts attributed by Southland
Royalty to royalties and production taxes. Southland Royalty retained a total
of $6,700,000 from the settlement proceeds that it attributed to quantity
claims.

  Because of the difficulty in determining the exact value of consideration
received under the renegotiated contracts referred to below, Southland Royalty
informed the Trust that it would not attribute value to quantity claims under
the renegotiated contracts and the Trust shall receive 75% (the amount of its
net overriding royalty interest) of any value that ultimately inures to those
contracts.

  Southland Royalty also informed the Trust that the settlement also provided
for new gas purchase agreements replacing the then current intrastate and
interstate gas purchase agreements. Southland Royalty entered into five-year
gas purchase, gas processing and gas gathering agreements with Sunterra and
Gas Company that were effective as of July 1, 1990. The new contracts applied
to all lands previously dedicated to Sunterra and Gas Company for first sales
of natural gas sold into interstate or intrastate markets, except that the new
gas purchase contracts exclude all gas produced and sold from coal seam wells.
The new gas purchase contracts provided for purchase rights and obligations
during the winter heating season only. During the remainder of the year,
Southland Royalty through MOTI could market the gas through any arrangements
it deemed advisable. Under the new gas contracts, Southland Royalty would
receive prices, inclusive of severance taxes, ranging from approximately $2.35
per month MMBtu to $3.37 per MMBtu over the life of the contracts. The
contracts provided for certain "take-or-pay obligations" if specified
quantities of gas (66% of the maximum volume that can be produced into the
gathering system against the Assumed Working Pressure of a purchase period and
lawfully made available for sale to the gas purchaser each day during a
purchase period) are not taken by the purchasers during the winter heating
season. Should the required minimum not be taken, then a reservation fee was
to be paid to Southland Royalty to be determined by multiplying 20% of the
price of gas for the applicable time period times the deficiency for the
purchase period. See Note 5 of Notes to Financial Statements of the Trust's
Annual Report to security holders for the year ended December 31, 1996 for
further discussion of this settlement and its impact upon the Trust.

  The gas gathering contract provided for transportation of gas not taken by
Sunterra and Gas Company during the winter heating season and during the
remainder of the year. The gas processing agreement provided that Southland
Royalty received 80% of the plant products derived from processing the gas.
The processing company was to retain the remaining 20% as its fee for
processing the gas.

  In 1991, due to the low level of natural gas prices, Sunterra informed
Southland Royalty that it would not take any significant volume of gas during
the 1991-1992 winter heating season and would simply pay the "take or pay
obligation" amount. Consequently, the majority of the wells subject to the
contracts would remain shut-in during the winter heating season. Southland
Royalty informed the Trustee that, in an attempt to maximize

                                       4
<PAGE>

production and revenue from the Trust properties, it had entered into an
agreement that would amend the terms of the contracts discussed above for only
the 1991-1992 winter heating season. The amendment provided that Sunterra and
Gas Company could purchase approximately 35% of the contract provided take
levels at a wellhead price slightly higher than the spot wellhead index price
for the San Juan Basin. Any gas purchased by Sunterra or Gas Company above
this level would average $2.63 per MMBtu. Southland Royalty would be free to
market the remaining deliverable gas to other purchasers. During 1992 Gas
Company and Sunterra purchased 702,629 Mcf and 3,241,500 Mcf, respectively, at
average prices of $2.25 and $1.98 per Mcf, respectively, from the properties
from which the Royalty was carved.

  Southland Royalty informed the Trust that a one year contract amendment was
agreed to with Gas Company and Sunterra for the 1992-1993 winter heating
season. Gas Company and Sunterra were required to purchase a minimum of 11,500
MMBtu per day under the intrastate contract and a minimum of 16,550 MMBtu per
day under the interstate contracts at the contract specified prices of $2.695
per MMBtu and $2.94 per MMBtu, respectively. A portion of the excess gas up to
9,000 MMBtu per day for the intrastate contracts and 12,000 MMBtu per day for
the interstate contracts was released for spot sales, with a recall provision
at an average contract price. Southland Royalty waived any claims for
deficiency payments under the reservation fees.

  Southland Royalty informed the Trust that a similar amendment was entered
into for the 1993-1994 winter heating season. Gas Company and Sunterra were
required to purchase a minimum of 1,696,485 MMBtu with an average minimum of
5,100 MMBtu per day under the intrastate contracts between November 1, 1993
and March 1994 and a minimum of 1,401,570 MMBtu with an average minimum of
7,000 MMBtu per day under the interstate contract between December 1, 1993 and
February 28, 1994 at the contract specified prices of $2.884 per MMBtu and
$3.146 per MMBtu, respectively. All remaining intrastate gas in excess of
11,300 MMBtu per day during the period November 1, 1993 and through March 31,
1994 and all remaining interstate gas in excess of 15,600 MMBtu per day during
the period December 1, 1993 through February 28, 1994 was released for spot
sales, with a recall provision at a price during the months of November 1993
and March 1994 of $2.884 per MMBtu and $3.015 per MMBtu for the months
December 1993, January 1994, and February 1994.

  Southland Royalty informed the Trust that an amendment was also entered into
for the 1994-1995 winter heating season. Gas Company and Sunterra were
required to purchase, at the wellhead, an average volume of 10,529 MMBtu per
day at $2.884 per MMBtu for the period beginning November 1, 1994 and ended
March 31, 1995 and an additional 14,900 MMBtu per day at $3.146 per MMBtu for
the period beginning December 1, 1994 and ended February 28, 1995. Gas Company
and Sunterra were granted a make-up period of four months beginning April 1,
1995 to fulfill this purchase obligation. Gas Company and Sunterra were also
granted recall rights on volumes up to 15,000 MMBtu per day at the tailgate of
the Kutz and Lybrook plants, provided they nominated the full contract volume
specified above. The price for recall was to be the average of the first and
second issues of the Inside FERC EPNG SJ Index.

  Southland Royalty also informed the Trust that effective July 1, 1995,
Williams Field Services ("Williams") purchased the Kutz and Lybrook processing
plants and the gathering systems behind these plants which were owned by
Sunterra, Gas Company and Sunterra Gas Processing Company ("SGPC") and that
new gathering and processing agreements with Williams have been entered into
which contain acceptable rates, terms and conditions. The new agreements
replaced the then current gathering and processing agreements with Gas
Company, Sunterra and SGPC effective on the closing date of the sale of these
facilities to Williams.

  The Trust has further been informed by Southland Royalty that MOTI
negotiated an agreement with Gas Company providing for transportation service
on Gas Company's Albuquerque mainline. This agreement was effective on the
closing date of the sale of Gas Company's gathering and processing facilities
to Williams. This transportation agreement facilitates delivery of volumes of
gas behind the Lybrook processing plant to mainline delivery points.

  Southland Royalty further informed the Trust that on September 13, 1994,
MOTI entered into a gas sales agreement with Gas Company for the five winter
periods beginning November 1, 1995 and ending March 31,

                                       5
<PAGE>

2000. MOTI purchased the gas supplied for this sale from MOI producing
affiliates and third party sellers. Sales were based on a monthly published
index. BROG has informed the Trust that as a result of the Litigation (as
hereinafter defined), no gas produced from the properties from which the
Royalty was carved will be applied in performance of such agreement with Gas
Company. It is the understanding of the Trustee that Gas Company is now known
as PNM Gas Services.

  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 Trust gas, oil and natural gas liquids products going forward
as follows:

    (i) BROG's pre-existing contract with a third-party purchaser will
  continue as pertains to baseload gas volumes in the firm amount of 45,000
  MMBtus/day for a period of one year from July 1, 1996. Negotiations for the
  sale of these volumes after June 30, 1997, will be entered into prior to
  the expiration of the primary term of the contract;

    (ii) The remaining volumes of Trust gas will be marketed by an
  independent marketer, El Paso Energy Marketing Company ("El Paso"), a
  subsidiary of El Paso Energy Corporation, beginning October 1, 1996, under
  an arrangement which provides for a sharing of amounts, if any, earned in
  excess of established gas price thresholds. El Paso's compensation for its
  marketing services consists solely of its proportionate part of any amounts
  for which the gas is sold in excess of the thresholds. BROG's contract with
  El Paso is for a two-year term beginning October 1, 1996, subject to
  renewal by agreement of the parties;

    (iii)BROG will continue to market the Trust oil and natural gas liquids
  but will remit to the Trust 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

    (iv) The Trust has retained access to BROG's current gas transportation,
  gathering, processing and treating agreements with third parties through
  the remainder or their primary terms. Additionally, El Paso may utilize
  BROG's eastern transportation agreement for delivery from the San Juan
  Basin on the El Paso Natural Gas Company pipeline to pipelines in West
  Texas of up to 13,333 MMBtu's/day of gas produced from Trust properties for
  a period of one year commencing October 1, 1996.

  See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 1996 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:

    "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.

    "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

                                       6
<PAGE>

  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 herein as "estimated future net cash flows."

    "Present value of estimated future net revenues" is computed using the
  estimated future net revenues and a discount rate of 10%.

  The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1994, 1995 and 1996 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1993
to December 31, 1996 (in thousands);

<TABLE>
<CAPTION>
                                                                        NATURAL
                                                                  OIL     GAS
                                                                 (BBLS)  (MCF)
                                                                 ------ -------
      <S>                                                        <C>    <C>
      Reserves as of December 31, 1993.........................    712  248,101
      Revisions of previous estimates..........................    (63) (31,236)
      Extensions, discoveries and other additions..............    -0-      -0-
      Production...............................................    (37) (15,460)
                                                                  ----  -------
      Reserves as of December 31, 1994.........................    612  201,405
      Revisions of previous estimates..........................   (165) (22,529)
      Extensions, discoveries and other additions..............    -0-      906
      Production...............................................    (29) (13,332)
                                                                  ----  -------
      Reserves as of December 31, 1995.........................    418  166,450
      Revisions of previous estimates..........................    272   95,106
      Extensions, discoveries and other additions..............      4    2,367
      Production...............................................    (37) (17,928)
                                                                  ----  -------
      Reserves as of December 31, 1996.........................    657  245,995
                                                                  ====  =======
</TABLE>

  Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1996, 1995 and 1994 were as follows (in thousands):

<TABLE>
<CAPTION>
                                                                  CRUDE  NATURAL
                                                                   OIL     GAS
                                                                  (BBLS)  (MCF)
                                                                  ------ -------
      <S>                                                         <C>    <C>
      1996.......................................................  637   239,962
      1995.......................................................  418   159,650
      1994.......................................................  612   186,915
</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.

                                       7
<PAGE>

  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 1996, 1995 and 1994 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>
                                                    1996      1995      1994
                                                  --------  --------  --------
      <S>                                         <C>       <C>       <C>
      Balance, January 1......................... $106,937  $157,627  $274,215
      Revisions of prior-year estimates, change
       in prices and other.......................  338,208   (51,819) (120,730)
      Extensions, discoveries and other
       additions.................................    4,612       522       -0-
      Accretion of discount......................   10,694    15,763    27,422
      Royalty income.............................  (21,414)  (15,156)  (23,280)
                                                  --------  --------  --------
      Balance, December 31....................... $439,037  $106,937  $157,627
                                                  ========  ========  ========
</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 $4.04 per Mcf of conventional gas, $2.84 per Mcf
of coal seam gas and $23.18 per Bbl of oil were used at December 31, 1996, in
determining future net revenue. The upward revision is primarily due to
significantly higher gas prices in December 1996.

  December average prices of $1.36 per Mcf of conventional gas, $0.85 per Mcf
of coal seam gas and $17.24 per Bbl of oil were used at December 31, 1995, in
determining future net revenue. The downward revision is primarily due to
lower gas prices in 1995.

  An average price of $1.56 per Mcf and $13.78 per barrel were used at
December 31, 1994, in determining estimated future net revenues. The downward
revision was primarily due to lower gas prices in 1994.

  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, 1996, 1995 and 1994 (in thousands except amounts per
Unit):

<TABLE>
<CAPTION>
                               1996               1995               1994
                        ------------------ ------------------ ------------------
                        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..........  $822,131  $439,037 $184,055  $106,937 $287,401  $157,627
Proved Developed......  $799,664  $430,365 $175,824  $104,378 $265,477  $149,241
Total Proved Per Unit.  $  17.64  $   9.42 $   3.95  $   2.29 $   6.17  $   3.38
</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,

                                       8
<PAGE>

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 or 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 ("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 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.

  Commencing in 1992, FERC issued Orders Nos. 636, 636-A, 636-B and 636-C
(collectively, "Order No. 636"), which generally opened access to interstate
gas pipelines by requiring such pipelines to "unbundle" their transportation
services and allow shippers to choose and pay for only the services they
require, regardless of whether the shipper purchases gas from such pipelines
or from other suppliers. These orders also require upstream pipelines to
permit downstream pipelines to assign upstream capacity to their shippers and
place analogous, unbundled access requirements on the downstream pipelines.
Through individual pipeline restructuring proceedings, Order No. 636 has been
implemented on all U.S. interstate pipelines. There are currently a number of
judicial challenges to these individual proceedings, which are now pending
before the U.S. Court of Appeals for the District of Columbia Circuit (the
"D.C. Circuit"). In July 1996, the D.C. Circuit largely upheld the terms of
the Order No. 636 rulemaking. Certain aspects of the D.C. Circuit's ruling
have been appealed to the U.S. Supreme Court.

  Although Order No. 636 does not regulate the Trust, FERC has stated that
Order No. 636 is intended to foster increased competition within all phases of
the natural gas industry. In many instances, the result of Order No. 636 and
related initiatives have been to substantially reduce or eliminate the
interstate pipelines' traditional role as wholesalers of natural gas in favor
of providing only storage and transportation services. It is unclear what
impact, if any, increased competition within the natural gas industry under
Order No. 636 will have on the Trust.

  The FERC has recently announced its intention to reexamine certain of its
transportation-related policies, including the appropriate manner for setting
rates for new interstate pipeline construction, the manner in which

                                       9
<PAGE>

interstate pipeline shippers may release interstate pipeline capacity under
Order No. 636 for resale in the secondary market, and the use of market-based
rates for interstate gas transmission. While any resulting FERC action would
affect the Trust only indirectly, FERC's stated intention is to further
enhance competition in natural gas markets.

  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 recently
pursued by the FERC and Congress will continue.

 Coal Seam Tax Credit

  The Trust began receiving royalty income from coal seam wells beginning in
1989. Under Section 29 of the Internal Revenue Code, production from coal seam
gas wells drilled prior to January 1, 1993, qualifies for the federal income
tax credit for producing non-conventional fuels. Production from wells drilled
after December 31, 1979 but prior to January 1, 1993, to a formation beneath a
qualifying coal seam formation which are later completed into such formation
also qualifies for the tax credit. This tax credit for 1996 was approximately
$1.03 per MMBtu and applies to production through the year 2002. Each Unit
holder must determine his pro rata share of such production based upon the
number of Units owned during each month of the year and apply the tax credit
against his own income tax liability, but such credit may not reduce his
regular 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 taxypayer'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.

 Other Regulation

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

ITEM 3. LEGAL PROCEEDINGS

  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 Trust 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. 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
Trust 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.

                                      10
<PAGE>

  The $19,750,000 (or $.423739 per unit of beneficial interest) was paid to
the Trust on September 30, 1996 and distributed on October 15, 1996, to unit
holders of record as of September 30, 1996, (the "Record Date"). The
distribution is taxable to unit holders as of such Record Date. This
distribution was in addition to the regular monthly distribution on October
15, 1996.

  For additional information concerning legal proceedings, Notes 5 and 6 of
the Notes to Financial Statements at pages 13 through 15 of the Trust's Annual
Report to security holders for the year ended December 31, 1996 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, 1996.

                                      11
<PAGE>

                                    PART II

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

  The information under "Units of Beneficial Interest" at page 2 of the
Trust's Annual Report to security holders for the year ended December 31,
1996, is herein incorporated by reference.

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                        FOR THE YEAR ENDED DECEMBER 31,
                          -----------------------------------------------------------
                             1996        1995        1994        1993        1992
                          ----------- ----------- ----------- ----------- -----------
<S>                       <C>         <C>         <C>         <C>         <C>
Royalty income(1).......  $41,236,424 $15,156,292 $23,280,188 $37,576,121 $32,494,453
Distributable income....   37,803,167  13,790,101  22,632,493  36,760,797  31,705,994
Distributable income per
 Unit...................     0.811072    0.295867    0.485584    0.788710    0.680257
Distributions per Unit..     0.811072    0.295867    0.485584    0.788710    0.680257
Total assets, December
 31.....................   65,935,976  70,554,982  75,531,405  82,701,203  90,372,116
</TABLE>
--------
(1) The royalty income distributions for 1992 and 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
1996 and 1995" at pages 6, 7, and 9 of the Trust's Annual Report to security
holders for the year ended December 31,1996, are herein incorporated by
reference.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

  The Financial Statements of the Trust and the and the notes thereto at page
10 et seq., of the Trust's Annual Report to security holders for the year
ended December 31, 1996, are herein incorporated by reference.

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

  None.

                                      12
<PAGE>

                                   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

  During the year ended December 31, 1996, the Trustee received total
remuneration as follows:

<TABLE>
<CAPTION>
      NAME OF INDIVIDUAL OR NUMBER OF
             PERSONS IN GROUP           CAPACITIES IN WHICH SERVED CASH COMPENSATION
      -------------------------------   -------------------------- -----------------
      <S>                               <C>                        <C>
      Bank One, Texas, N.A......                 Trustee              $189,219(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, 1996, 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
           NAME AND ADDRESS            OF BENEFICIAL OWNERSHIP PERCENT OF CLASS
           ----------------            ----------------------- ----------------
<S>                                    <C>                     <C>
Fund American Enterprises Holdings,
 Inc. (1).............................    10,994,876 Units           23.6%
 The 1820 House, Main Street
 Norwich, Vermont 05055
Capital Guardian Trust Company (2)....     4,004,800 Units            8.6%
 333 South Hope Street, 52nd Floor
 Los Angeles, California 90071
</TABLE>
--------
(1) This information was provided to the Securities and Exchange Commission
    and to the Trust in a Form 4 dated July 9, 1996, filed with the Securities
    and Exchange Commission by Fund American Enterprises Holdings, Inc.
    ("FAEH") which indicated that these Units were owned by FAEH.
  According to such Form 4, FAEH owns 157,215 Units directly and 10,837,661
  Units indirectly as follows: 10,759,876 Units indirectly through its
  wholly-owned subsidiary Fund American Enterprises, Inc. ("FAE") and 77,785
  Units indirectly through its wholly-owned subsidiary White Mountain
  Holdings, Inc. and certain of its wholly-owned subsidiaries.
  The Form 4 filed by FAEH with the Securities and Exchange Commission may be
  reviewed for more detailed information concerning the matters summarized
  herein.
(2) This information was provided to the Securities and Exchange Commission
    and to the Trust in Amendment 3 to Schedule 13G dated February 12, 1997,
    filed jointly with the Securities and Exchange Commission by The Capital
    Group Companies, Inc. ("Capital Group") and Capital Guardian Trust Company
    ("Capital Guardian"). Capital Guardian is a bank wholly-owned operating
    subsidiary of Capital Group. Capital Guardian exercised investment
    discretion with respect to the 4,004,800 Units which were owned by various
    institutional investors. Capital Group disclaims beneficial ownership of
    such Units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934.
    Both Capital Group and Capital Guardian report sole voting power over
    3,249,800 Units and sole dispositive power over 4,004,800 Units.

  The Amendment 3 to Schedule 13G filed by Capital Group and Capital Guardian
  with the Securities and Exchange Commission may be reviewed for more
  detailed information concerning the matters summarized herein.

                                      13
<PAGE>

  (b) Security Ownership of Management. The Trustee owns beneficially no
securities of the Trust. In various fiduciary capacities, Bank One, Texas, NA
owned, as of December 31, 1996, an aggregate of 23,672 Units with the sole
right to vote 7,520 of these Units and shared right to vote 16,152 of these
Units. Such Bank 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, 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, 1996
and Item 12(b) for information concerning Units owned by Bank One, Texas, NA
in various fiduciary capacities.

                                    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, 1996:

  Independent Auditors' Report
  Statement 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.

EXHIBITS

<TABLE>
 <C>    <S>
 (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, NA), as Trustee, heretofore filed as Exhibit
         4(a) to the Trust's Annual Report on Form 10-K to the Securities and
         Exchange Commission 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, 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
         Securities and Exchange Commission 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, 1996.**
   (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, NA,
   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, 1996, no
reports on Form 8-K were filed with the Securities and Exchange Commission by
the Trust.

                                      14
<PAGE>

                                   SIGNATURE

  PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES AND
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, NA
                                          TRUSTEE OF THE SAN JUAN BASIN
                                           ROYALTY TRUST

                                                    /s/ Lee Ann Anderson
                                          By: _________________________________
                                                   (Lee Ann Anderson)
                                                     Vice President

Date: March 31, 1997

              (The Trust has no directors or executive officers)

                                      15