<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

                For the fiscal year ended December 31, 1997, 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)

<TABLE>
<S>                                            <C>
                    TEXAS                                        75-6279898
       (STATE OR OTHER JURISDICTION OF                       (I.R.S. EMPLOYER
       INCORPORATION OR ORGANIZATION)                     IDENTIFICATION NUMBER)
            BANK ONE, TEXAS, N.A.                                  76113
               TRUST DEPARTMENT                                  (ZIP CODE)
                P. O. BOX 2604
              FORT WORTH, TEXAS
   (ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
</TABLE>

                                (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 REGISTERED
-------------------------------------  ---------------------------------------
    Units of Beneficial Interest               New York Stock Exchange

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

                                     NONE

                               (Title of Class)

  Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to
such filing requirements for the past 90 days. Yes [X] No [_]

  Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

  At March 25, 1998, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $372,870,368.

                      DOCUMENTS INCORPORATED BY REFERENCE

  "Units of Beneficial Interest" at page 2; "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 1997 and 1996" 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, 1997 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, 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 Trust receives

                                       1
<PAGE>

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.

  As the year 2000 approaches, there are uncertainties concerning whether
computer systems will properly recognize date-sensitive information when the
year changes to 2000. Systems that do not properly recognize such information
could generate erroneous data or fail. The Trust is in communication with
third parties with which it deals, but it is not yet possible to fully assess
the effect of a third party's inability to adequately address year 2000
issues.

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 the Trustee by BROG.

                                       2
<PAGE>

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. Based upon information received from the Trust's
independent petroleum engineers, the Trust properties contain 3,038 gross (909
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, 1997, 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 1997, BROG incurred approximately $7.2 million of capital
expenditures for the drilling and completion of 64 gross (3.53 net)
conventional wells, recompletion of 14 gross (5.4 net) conventional wells,
drilling and completion of 1 gross (.84 net) coal seam well, and 21 gross
(2.32 net) coal seam recavitations. There were 5 (1.22 net) new conventional
wells, 3 (1.08 net) conventional recompletions, 11 gross (.42 net) coal seam
recompletions, 5 (.20 net) coal seam recavitations, and 1 (.04 net) coal seam
well in progress as of December 31, 1997. 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.

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, 1997
were as follows:

<TABLE>
<CAPTION>
                           1997                1996                1995
                    ------------------- ------------------- -------------------
                      OIL       GAS       OIL       GAS       OIL       GAS
                    (BBLS)     (MCF)     (BBLS)    (MCF)     (BBLS)    (MCF)
                    ------- ----------- ------- ----------- ------- -----------
<S>                 <C>     <C>         <C>     <C>         <C>     <C>
Production.........  50,860  24,236,419  36,792  17,927,785  29,424  13,331,758
Average Price...... $ 19.35 $      2.21 $ 19.64 $      1.30 $ 14.43 $      1.25
</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 41,948,567 Mcf during
1997.

  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.

                                       3
<PAGE>

  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 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 would receive 75% (the amount of its
net overriding royalty interest) of any value that ultimately inured 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, 1997 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.

                                       4
<PAGE>

  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 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.

  The Trust was informed 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 were 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.

  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.

                                       5
<PAGE>

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 covering
  baseload gas volumes in the firm amount of 45,000 MMBtus/day was to remain
  effective for a period of one year from July 1, 1996. The remaining volumes
  of Trust gas were marketed by an independent marketer, El Paso Energy
  Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation,
  beginning October 1, 1996. BROG agreed that 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 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

    (iii)  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
  could 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.

  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. While it is impossible to predict the
exact economic value of gas contracts, the Trust has been advised by its
independent gas marketing consultant that the contract with El Paso should
provide for the average highest sales price for natural gas in the San Juan
Basin over the two-year term of the contract.

  See Note 5 of Notes to Financial Statements of the Trust's Annual Report to
securityholders for the year ended December 31, 1997 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 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."

                                       6
<PAGE>

    "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, 1995, 1996 and 1997 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1994
to December 31, 1997 (in thousands):

<TABLE>
<CAPTION>
                                                                        NATURAL
                                                                  OIL     GAS
                                                                 (BBLS)  (MCF)
                                                                 ------ -------
   <S>                                                           <C>    <C>
   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
                                                                  ----  -------
   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
                                                                  ====  =======
  Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1997, 1996 and 1995 were as follows (in thousands):
<CAPTION>
                                                                 CRUDE  NATURAL
                                                                  OIL     GAS
                                                                 (BBLS)  (MCF)
                                                                 ------ -------
   <S>                                                           <C>    <C>
   1997.........................................................   547  199,753
   1996.........................................................   637  239,962
   1995.........................................................   418  159,650
</TABLE>

  Generally, the calculation of oil and gas reserves takes into account a
comparison of the value of the oil or gas to the cost of producing those
minerals, in an attempt to cause minerals in the ground to be included in
reserve estimates only to the extent that the anticipated costs of production
will be exceeded by the anticipated sales revenue. Accordingly, an increase in
sales price and/or a decrease in production cost can itself result in an
increase in estimated reserves and declining prices and/or increasing costs
can result in reserves reported at less than the physical volumes actually
thought to exist. The Financial Accounting Standards Board requires
supplemental disclosures for oil and gas producers based on a standardized
measure of discounted future net cash flows relating to proved oil and gas
reserve quantities. Under this disclosure, future cash inflows are estimated
by applying year-end prices of oil and gas relating to the enterprise's proved
reserves to the year-end quantities of those reserves. Future price changes
are only considered to the extent provided by contractual arrangements in
existence at year-end. The standardized measure of discounted future net cash
flows is achieved by using a discount rate of 10% a year to reflect the timing
of future net cash flows relating to proved oil and gas reserves.

  Estimates of proved oil and gas reserves are by their nature imprecise.
Estimates of future net revenue attributable to proved reserves are sensitive
to the unpredictable prices of oil and gas and other variables. Accordingly,
under the allocation method used to derive the Trust's quantity of proved
reserves, changes in prices will result in changes in quantities of proved oil
and gas reserves and estimated future net revenues.

                                       7
<PAGE>

  The 1997, 1996 and 1995 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>
                                                   1997       1996      1995
                                                 ---------  --------  --------
   <S>                                           <C>        <C>       <C>
   Balance, January 1........................... $ 439,037  $106,937  $157,627
   Revisions of prior-year estimates, change in
   prices
    and other...................................  (227,855)  338,208   (51,819)
   Extensions, discoveries and other additions..     7,915     4,612       522
   Accretion of discount........................    43,904    10,694    15,763
   Royalty income...............................   (49,497)  (21,414)  (15,156)
                                                 ---------  --------  --------
   Balance, December 31......................... $ 213,504  $439,037  $106,937
                                                 =========  ========  ========
</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 $2.21 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.

  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 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, 1997, 1996 and 1995 (in thousands except amounts per
Unit):

<TABLE>
<CAPTION>
                                   1997               1996               1995
                            ------------------ ------------------ ------------------
                            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............ $372,830  $213,504 $822,131  $439,037 $184,055  $106,937
   Proved Developed........ $365,509  $211,580 $799,664  $430,365 $175,824  $104,378
   Total Proved Per Unit... $   8.00  $   4.58 $  17.64  $   9.42 $   3.95  $   2.29
</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.

                                       8
<PAGE>

  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 (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 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 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. The ultimate impact of the rules and regulations issued
by the FERC since 1985 cannot be predicted. In addition, many aspects of these
regulatory developments have not become final but are still pending judicial
and FERC final decisions.

  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.

  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. The Trust is not able to predict what effect, if any, these
regulations will have on it, but other factors being equal, the regulations
may tend to increase transportation costs or reduce wellhead prices for crude
oil.

 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
qualifying coal seam formation which are later completed into such formation
also qualifies for the tax credit. This tax credit for 1997 was approximately
$1.05 per MMBtu and applies to production through the year 2002. Each
Unitholder must determine his pro rata share

                                       9
<PAGE>

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 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.

 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 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. 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 $19,750,000 (or $.423739 per unit of beneficial interest) was paid to
the Trust on September 30, 1996 and distributed on October 15, 1996, to
unitholders 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, Note 5 of the Notes
to Financial Statements at pages 13 and 14 of the Trust's Annual Report to
security holders for the year ended December 31, 1997 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, 1997.

                                      10
<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 1 of the Trust's
Annual Report to security holders for the year ended December 31,1997, is
herein incorporated by reference.

ITEM 6. SELECTED FINANCIAL DATA

<TABLE>
<CAPTION>
                                          FOR THE YEAR ENDED DECEMBER 31,
                          ----------------------------------------------------------------
                              1997         1996         1995         1994         1993
                          ------------ ------------ ------------ ------------ ------------
<S>                       <C>          <C>          <C>          <C>          <C>
Royalty income(1).......  $ 49,497,479 $ 41,236,424 $ 15,156,292 $ 23,280,188 $ 37,576,121
Distributable income....    48,648,930   37,803,167   13,790,101   22,632,493   36,760,797
Distributable income per
Unit....................      1.043770     0.811072     0.295867     0.485584     0.788710
Distributions per Unit..      1.043770     0.811072     0.295867     0.485584     0.788710
Total assets, December
31......................    61,231,280   65,935,976   70,554,982   75,531,405   82,701,203
</TABLE>
--------
(1) The royalty income distributions for 1993 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
1997 and 1996" at pages 7 through 9 of the Trust's Annual Report to
securityholders for the year ended December 31, 1997, are herein incorporated
by reference.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK

Not applicable

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, 1997, are herein incorporated by reference.

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

  None.

                                       11
<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
Unitholders, 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, 1997, 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       $132,880(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, 1997, 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>
      Fund American Enterprises
       Holdings, Inc.(1) ...............    5,994,876 Units         14.4%
       80 South Main Street
       Hanover, New Hampshire 03755
      Capital Guardian Trust Company
       (2)..............................    4,078,800 Units          8.8%
       333 South Hope Street, 52nd Floor
       Los Angeles, California 90071
</TABLE>
--------
(1) This information was provided to the Trust on Form 4, dated December 3,
    1997, as filed with the Securities and Exchange Commission (the "SEC") by
    Fund American Enterprises Holdings, Inc.("FAEH"), which indicated that
    these Units were owned by Fund American Enterprises, Inc.

  The Form 4 and an Amendment Number 8 to Schedule 13D, dated December 2,
  1997 filed by FAEH with the SEC may be reviewed for more detailed
  information concerning the matters summarized herein.

(2) This information was provided to the SEC and to the Trust in Amendment
    Number 4 to Schedule 13G, dated February 10, 1998, filed jointly by The
    Capital Group Companies, Inc. ("Capital Group") and Capital Guardian Trust
    Company ("Capital Guardian"). Capital Guardian is a wholly-owned operating
    subsidiary of Capital Group. Capital Guardian exercised investment
    discretion with respect to the 4,078,800 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
    3,403,800 Units and sole dispositive power over 4,078,800 Units.

  The Amendment Number 4 to Schedule 13G filed by Capital Group and Capital
  Guardian with the SEC may be reviewed for more detailed information
  concerning the matters summarized herein.

                                     III-1
<PAGE>

  (b) Security Ownership of Management. In various fiduciary capacities, Bank
One, Texas, N.A. owned, as of December 31, 1997, an aggregate of 29,272 Units
with the sole right to vote 23,672 of these Units and no right to vote 5,600
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, 1997
and Item 12(b) for information concerning Units owned by Bank One, Texas, N.A.
in various fiduciary capacities.

                                     III-2
<PAGE>

                                    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, 1997:

  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.

<TABLE>
<CAPTION>
 EXHIBITS
 <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, 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, 1997.**
  (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.

REPORTS ON FORM 8-K

  During the last quarter of the Trust fiscal year ended December 31, 1997, no
reports on Form 8-K were filed with the Securities and Exchange Commission by
the Trust.

                                     IV-1
<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, N.A.
                                          TRUSTEE OF THE SAN JUAN BASIN
                                           ROYALTY TRUST

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

Date: March 31, 1998

              (The Trust has no directors or executive officers)