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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, 1995, 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 No.)
 
          BANK ONE, TEXAS, NA                            76113
            TRUST DEPARTMENT                           (Zip Code)
             P.O. BOX 2604
           FORT WORTH, TEXAS
    (Address of Principal Executive
                Offices)
                                 (817) 884-4630
              (Registrant's Telephone Number, Including Area Code)
 
          Securities registered pursuant to Section 12(b) of the Act:
 


                                     NAME OF EACH EXCHANGE
          TITLE OF EACH CLASS         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 April 10, 1996, there were 46,608,796 Units of Beneficial Interest of the
Trust outstanding with an aggregate market value on that date of $273,826,676.
 
                      DOCUMENTS INCORPORATED BY REFERENCE
 
  "Units of Beneficial Interest" at page 2; "Description of Properties" at page
4; "Trustee's Discussion and Analysis for the Three-Year Period Ended December
31, 1995" at pages 6 and 7; "Results of the 4th Quarters of 1995 and 1994" at
page 8; and "Statements of Assets, Liabilities and Trust Corpus," "Statements
of Distributable Income," "Statements of Changes in Trust Corpus," "Notes to
Financial Statements," and "Independent Auditors' Report" at page 10 et seq.,
in registrant's Annual Report to security holders for fiscal year ended
December 31, 1995 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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                                     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
817/884-4630).
 
  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 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. In March 1992, El Paso completed an initial public
offering of 5,750,000 newly issued shares of El Paso common stock, thereby
decreasing BRI's ownership of El Paso to approximately eighty-five percent
(85%). On June 30, 1992, BRI distributed all of the shares of El Paso common
stock owned by BRI to BRI's stockholders of record as of June 15, 1992. See
"Pricing Information" under "Item 2. Properties" herein.
 
  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.
 
  The term "net proceeds" as used in the October 23, 1980 conveyance means the
excess of "gross proceeds" received by MOI during a particular period over
"production costs" for such period. "Gross proceeds" means the amount received
by MOI (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
 
                                       1

 
carved, subject to certain adjustments. "Production costs" means, generally,
costs incurred on an accrual basis by MOI in operating its properties and
interests out of which the Royalty was carved, including both capital and non-
capital costs; for example, 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 liable for any production costs or other costs or liabilities attributable
to these properties and interests or the minerals produced thereform. If at any
time the Trust receives more than the amount due under the Royalty, it shall
not be obligated to return such overpayment, but the amounts payable to it for
any subsequent period shall be reduced by such amount, plus interest, at a rate
specified in the conveyance.
 
  Certain of the properties and interests out of which the Royalty was carved
are operated by MOI with the obligation to conduct its operations in accordance
with reasonable and prudent business judgment and good oil and gas field
practices. As operator, MOI 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. MOI 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 reasonably obtainable in the
circumstances. MOI also has the obligation to maintain books and records
sufficient to determine the amounts payable to the Trustee. MOI, 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 MOI in
the second month, the net proceeds attributable to the Royalty are paid by MOI
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 interests and royalty interests in the San Juan
Basin in northwestern New Mexico. References below to "net" wells and acres are
to the interests of Southland Royalty (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 Southland Royalty or MOI.
 
                                       2

 
PRODUCING ACREAGE, WELLS AND DRILLING
 
  MOI'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 2,906 gross (944 net)
economic wells, including dual completions. A dispute between the Trustee and
MOI as to the well count is an issue in the litigation pending in Santa Fe
County, New Mexico. See "Item 3. Legal Proceedings". 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, 1995, 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 MOI.
 
  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. During 1993, there were 31 gross (13.9 net) wells completed
including 18 gross (8.27 net) coal seam wells.
 
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, 1995
were as follows:
 


                                1995              1994              1993
                          ----------------- ----------------- -----------------
                           OIL               OIL               OIL
                          (BBLS) GAS (MCF)  (BBLS) GAS (MCF)  (BBLS) GAS (MCF)
                          ------ ---------- ------ ---------- ------ ----------
                                                   
      Production......... 29,424 13,331,758 36,769 15,459,542 51,921 23,895,506
      Average Price...... $14.43      $1.25 $13.09      $1.66 $15.58      $1.70

 
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. Production from the properties
from which the Royalty was carved totalled 34,387,190 Mcf during 1995.
 
  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").
 
  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. MOTI presently markets gas, including
gas produced from properties in which the Trust owns an interest, under short-
term arrangements to end users.
 
                                       3

 
  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 judgement 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.
 
  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 or 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 purchase contracts, Southland Royalty would
receive prices, inclusive of severance taxes, ranging from approximately $2.35
per 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 2/3% 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 must 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 6 of Notes to Financial Statements of the Trust's Annual Report to
security holders for the year ended December 31, 1995 for further discussion of
this settlement and its impact upon the Trust.
 
                                       4

 
  The gas gathering contract provides 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 would receive 80% of the plant products derived from processing the
gas. The processing company would 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 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 3,241,550 Mcf, respectively, at average
prices of $2.25 and $1.98 per Mcf 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 ending March 31,
1995 and an additional 14,900 MMBtu per day at $3.146 per MMBtu for the period
beginning December 1, 1994 and ending 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 have 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
 
                                       5

 
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 will be necessary to deliver volumes of
gas behind the Lybrook processing plant to mainline delivery points.
 
  Southland Royalty has further informed the Trust that on September 13, 1994,
MOTI, one of the first purchasers of MOI producing affiliates' gas, entered
into a gas sales agreement with Gas Company for the next five winter periods
beginning November 1, 1995 and ending March 31, 2000. MOTI will be purchasing
the gas supplied for this sale from MOI producing affiliates and other third
party sellers. Sales will be based on a monthly published index. Valid delivery
points under the agreement will be the tailgate of the Lybrook Plant, the
tailgate of the Kutz Plant, the Blanco Hub, or Rio Puerco.
 
  It is the understanding of the Trustee that Gas Company is now known as PNM
Gas Services.
 
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".
 
    "Present value of estimated future net revenues" is computed using the
  estimated future net revenues and a discount rate of 10%.
 
                                       6

 
  The independent petroleum engineers' reports as to the proved oil and gas
reserves as of December 31, 1993, 1994 and 1995 were prepared by Cawley,
Gillespie & Associates, Inc. The following table presents a reconciliation of
proved reserve quantities attributable to the Royalty from December 31, 1992 to
December 31, 1995 (in thousands):
 


                                                                        NATURAL
                                                                  OIL     GAS
                                                                 (BBLS)  (MCF)
                                                                 ------ -------
                                                                  
      Reserves as of December 31,1992...........................   780  254,512
      Revisions of previous estimates...........................   (16)  14,995
      Extensions, discoveries and other additions...............   -0-    2,490
      Production................................................   (52) (23,896)
                                                                  ----  -------
      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
                                                                  ====  =======

 
  Estimated quantities of proved developed reserves of crude oil and natural
gas as of December 31, 1995, 1994 and 1993 were as follows (in thousands):
 


                                                                  CRUDE  NATURAL
                                                                   OIL     GAS
                                                                  (BBLS)  (MCF)
                                                                  ------ -------
                                                                   
      1995.......................................................  418   159,650
      1994.......................................................  612   186,915
      1993.......................................................  712   230,736

 
  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 very 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 1995, 1994 and 1993 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):
 


                                                   1995      1994       1993
                                                 --------  ---------  --------
                                                             
      Balance, January 1........................ $157,627  $ 274,215  $263,525
      Revisions of prior-year estimates, change
       in prices and other......................  (51,819)  (120,730)   19,066
      Extensions, discoveries and other
       additions................................      522        -0-     2,847
      Accretion of discount.....................   15,763     27,422    26,353
      Royalty income............................  (15,156)   (23,280)  (37,576)
                                                 --------  ---------  --------
      Balance, December 31...................... $106,937  $ 157,627  $274,215
                                                 ========  =========  ========

 
                                       7

 
  Reserve quantities and revenues shown in the tables above for the Royalty
were estimated from projections of reserves and revenues attributable to the
combined MOI 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. Royalty income related to the settlement with PNM is not
included in the royalty income for 1992 because it does not relate to
production for that year and is not included in estimated future net cash
flows. 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 $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.
 
  An average price of $2.14 per Mcf and $10.94 per barrel were used at December
31, 1993, in determining estimated future net revenues.
 
  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, 1995, 1994 and 1993 (in thousands except amounts per Unit):
 


                                1995               1994               1993
                         ------------------ ------------------ ------------------
                         ESTIMATED          ESTIMATED          ESTIMATED
                          FUTURE   PRESENT   FUTURE   PRESENT   FUTURE   PRESENT
                            NET    VALUE AT    NET    VALUE AT    NET    VALUE AT
                          REVENUE    10%     REVENUE    10%     REVENUE    10%
                         --------- -------- --------- -------- --------- --------
                                                       
Total Proved............ $184,055  $106,937 $287,401  $157,627 $500,013  $274,215
                         ========  ======== ========  ======== ========  ========
Proved Developed........ $175,824  $104,378 $265,477  $149,241 $464,132  $261,536
                         ========  ======== ========  ======== ========  ========
Total Proved Per Unit...    $3.95     $2.29    $6.17     $3.38   $10.73     $5.88
                         ========  ======== ========  ======== ========  ========

 
  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. The Federal Energy
Regulatory Commission ("FERC") is primarily responsible for federal regulation
of natural gas.
 
 Natural Gas Regulation
 
  The interstate transportation and sale for resale of natural gas is subject
to federal governmental regulation, including regulation of tariffs charged and
various other matters, by FERC. The Natural Gas Wellhead Decontrol Act of 1989
terminated federal price controls on wellhead sales of domestic natural gas on
January 1, 1993.
 
                                       8

 
  In 1992, FERC issued Orders Nos. 636 and 636-A, 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.
 
 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. This tax credit for 1995 was
approximately $1.01 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 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 petroleum 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
 
  For information concerning legal proceedings, Notes 5 and 6 of the Notes To
Financial Statements at pages 12 through 15 of the Trust's Annual Report to
security holders for the year ended December 31, 1995 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, 1995.
 
                                       9

 
                                    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, 1995, is
herein incorporated by reference.
 
ITEM 6. SELECTED FINANCIAL DATA
 


                                        FOR THE YEAR ENDED DECEMBER 31,
                          -----------------------------------------------------------
                             1995        1994        1993        1992        1991
                          ----------- ----------- ----------- ----------- -----------
                                                           
Royalty income..........  $15,156,292 $23,280,188 $37,576,121 $32,494,453 $21,639,360
Distributable income....   13,790,101  22,632,493  36,760,797  31,705,994  21,142,738
Distributable income per
 Unit...................     0.295867    0.485584    0.788710    0.680257    0.453621
Distributions per Unit..     0.295867    0.485584    0.788710    0.680257    0.453621
Total assets, December
 31.....................   70,554,982  75,531,405  82,701,203  90,372,116  94,236,689

 
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
1995 and 1994" at pages 6, 7 and 8 of the Trust's Annual Report to security
holders for the year ended December 31, 1995, are herein incorporated by
reference.
 
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
  The Financial Statements of the Trust and the notes thereto at page 10 et
seq., of the Trust's Annual Report to security holders for the year ended
December 31, 1995, are herein incorporated by reference.
 
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
       FINANCIAL DISCLOSURE
 
  There have been no changes in accountants and no disagreements with
accountants on any matter of accounting principles or practices or financial
statement disclosures during the twenty-four months ended December 31, 1995.
 
                                    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, 1995, the Trustee received total
remuneration as follows:
 


            NAME OF INDIVIDUAL
               OR NUMBER OF                                             CASH
             PERSONS IN GROUP          CAPACITIES IN WHICH SERVED   COMPENSATION
            ------------------        ----------------------------- ------------
                                                              
      Bank One, Texas, NA............ Trustee and Transfer Agent(1) $127,974(2)

- --------
(1) Effective October 1995, Harris Trust & Savings Bank became the transfer
    agent of the Trust.
(2) 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
 
                                       10

 
   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.
   The Trustee may also charge a transfer agency fee if acting in that
   capacity. Of the amount stated in the table above, $106,328 was in payment
   of the Trustee's administrative fee. The balance of $21,646 was in payment
   of the Trustee's transfer agency fee.
 
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, 1995, information with respect to each person known
to own beneficially more than 5% of the outstanding Units of the Trust:


                                                          AMOUNT AND
                                                          NATURE OF     PERCENT
                                                          BENEFICIAL      OF
                    NAME AND ADDRESS                      OWNERSHIP      CLASS
                    ----------------                   ---------------- -------
                                                                  
   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)..................  3,809,400 Units   8.2%
     333 South Hope Street, 52nd Floor
     Los Angeles, California 90071

- --------
(1) This information was provided to the Securities and Exchange Commission and
    to the Trust in a Form 4 dated January 5, 1996, filed with the Securities
    and Exchange Commission by The Fund American Enterprises Holdings, Inc.
    ("FAEH") which indicated that these Units were owned by FAEH.
  According to such Form 4, FAEH owns such 10,994,876 Units indirectly:
  2,516,927 Units indirectly through its wholly-owned subsidiary FFOG, Inc.,
  8,242,949 Units indirectly through its wholly-owned subsidiary Fund
  American Enterprises, Inc. ("FAE") and 235,000 Units indirectly through
  FAE's 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 2 to Schedule 13G dated February 9, 1996, 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 3,809,400 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
    3,054,400 Units and sole dispositive power over 3,809,400 Units.
  The Amendment 2 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.
 
  (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, 1995 an aggregate of 24,538 Units with the sole right
to vote 8,386 of these Units and shared right to vote 16,152 of these Units.
Such Bank disclaims any beneficial interests 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, 1995
and Item 12(b) for information concerning Units owned by Bank One, Texas, NA in
various fiduciary capacities.
 
                                       11

 
                                    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, 1995:
 
    Independent Auditors' Report
 
    Statements of Assets, Liabilities and Trust Corpus
 
    Statements of Distributable Income
 
    Statements of Changes in Trust Corpus
 
    Notes to Financial Statements
 
FINANCIAL STATEMENT SCHEDULES
 
  Financial statement schedules are omitted because of the absence of
conditions under which they are required or because the required information is
given in the financial statements or notes thereto.
 
EXHIBITS
 

       
   (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 Fort 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, 1995.**
  (23)    --Consent of Cawley, Gillespie & Associates, Inc., reservoir
           engineer.**
  (27)    --Financial Data Schedule.**

- --------
  * A copy of this Exhibit is available to any Unit holder, at the actual cost
    of reproduction, upon written request to the Trustee, Bank One, Texas, 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, 1995, one
report on Form 8-K was filed with the Securities and Exchange Commission by the
Trust. This Form 8-K relates to the lawsuit filed in New Mexico referenced in
"Item 3. Legal Proceedings" herein.
 
  The Form 8-K dated December 1, 1995, reported that with regard to the lawsuit
filed by the Trustee of the Trust against MOI and Southland Royalty in the
state district court in Santa Fe County, New Mexico, in Cause No. SF94-1982(c),
a hearing was held on November 17, 1995 regarding the Trustee's motion for
leave to file its Second Amended Complaint. Such motion was granted by the
court. The Trustee filed the Second Amended Complaint to more fully
particularize the pleadings, the nature of the claims of liability in the case,
and the facts supporting alter ego and single business enterprise liability and
fraudulent concealment
 
                                       12

 
as it pertains to the defendants' statute of limitations defense and to assert
the following additional claims for relief: breach of express good faith duty,
constructive fraud, unjust enrichment and prima facie tort and to add claims in
the alternative of intentional interference with contract and of conspiracy. A
copy of such Second Amended Complaint was attached as an exhibit to the Form 8-
K.
 
  It was also reported that a hearing had been held on a motion filed by MOI
and Southland Royalty seeking a continuance of the February 1996 trial setting.
Such motion was granted at a hearing held on November 28, 1995. Trial is now
scheduled to begin July 15, 1996.
 
  No financial statements were required to be filed in connection with the
filing of this Form 8-K.
 
                                       13

 
                                   SIGNATURE
 
  PURSUANT TO THE REQUIREMENTS OF SECTION 13 OR 15(D) OF THE SECURITIES
EXCHANGE ACT OF 1934, THE REGISTRANT HAS DULY CAUSED THIS REPORT TO BE SIGNED
ON ITS BEHALF BY THE UNDERSIGNED, THEREUNTO DULY AUTHORIZED.
 
                                     Bank One, Texas, NA
                                        Trustee of the San Juan Basin Royalty
                                         Trust
 
                                                /s/ Lee Ann Anderson
                                     By________________________________________
                                                 (Lee Ann Anderson)
                                                   Vice President
 
Date: April 15, 1996
 
              (The Trust has no directors or executive officers.)
 
                                       14

 
                               INDEX TO EXHIBITS
 


                                                                   SEQUENTIALLY
 EXHIBIT                                                             NUMBERED
 NUMBER                           EXHIBIT                              PAGE
 -------                          -------                          ------------
                                                             
    (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 Fort 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, 1995.**
   (23)    --Consent of Cawley, Gillespie & Associates, Inc.,
            reservoir engineer.**
   (27)    --Financial Data Schedule**

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