<PAGE>
                                                                      EXHIBIT 13

                                      SJT



                          SAN JUAN BASIN ROYALTY TRUST

                         ANNUAL REPORT & FORM 10K 2002

<PAGE>
                                   [PICTURE]
<PAGE>

                                    THE TRUST

The principal asset of the San Juan Basin Royalty Trust (the "Trust") consists
of a 75% net overriding royalty interest carved out of certain oil and gas
leasehold and royalty interests (the "Underlying Interests") in properties
located in the San Juan Basin of northwestern New Mexico.

UNITS OF BENEFICIAL INTEREST

The units of beneficial interest of the Trust ("Units") are traded on the New
York Stock Exchange under the symbol "SJT." At March 24, 2003, the latest
practicable date, the sale price of a Unit was $14.70. From January 1, 2001, to
December 31, 2002, quarterly high and low closing sales prices and the aggregate
amount of monthly distributions per Unit paid each quarter were as follows:

<Table>
<Caption>
                                                          Distributions
2002                                High           Low         Paid
----                                ----           ---    -------------
<S>                                <C>          <C>         <C>
First Quarter ................     $11.9000     $ 9.2500    $ .075673
Second Quarter ...............      12.2300      10.4900      .193414
Third Quarter ................      11.8800       9.7000      .263820
Fourth Quarter ...............      13.9000      11.7000      .248447
                                                            ---------
   Total for 2002 ............                              $ .781354
                                                            =========

2001
First Quarter ................     $16.1300     $12.3125    $ .799474
Second Quarter ...............      17.9800      12.4000      .563215
Third Quarter ................      14.0000      10.0800      .294257
Fourth Quarter ...............      11.5100       9.3000      .062177
                                                            ---------
   Total for 2002 ............                              $1.719123
                                                            =========
</Table>

At March 14, 2003, 46,608,796 Units outstanding were held by 1,972 Unit holders
of record. The following table presents information relating to the distribution
of ownership Units:

<Table>
<Caption>
                                                                            Number of
Type of Unit Holders                                                       Unit Holders   Units Held
--------------------                                                       ------------   ----------
<S>                                                                            <C>        <C>
Individuals, Individual Retirement Accounts, Joint Holders and Minors .....    1,735      2,150,801
Fiduciaries ...............................................................      187        528,484
Associations or Societies .................................................        8         89,335
Banks .....................................................................        5         13,560
Brokers, Dealers and Nominees .............................................        1     43,498,794
Corporations and Partnerships .............................................       30        326,833
Government Bodies .........................................................        6            989
                                                                               -----     ----------
   Total ..................................................................    1,972     46,608,796
                                                                               =====     ==========
</Table>

                                   [PICTURE]


<PAGE>

                                TO UNIT HOLDERS

We are pleased to present the 2002 Annual Report of the San Juan Basin Royalty
Trust. The report includes a copy of the Trust's Annual Report on Form 10-K to
the Securities and Exchange Commission for the year ended December 31, 2002,
without exhibits. The Form 10-K contains important information concerning the
Underlying Interests, defined below, including the oil and gas reserves
attributable to the net overriding royalty interest owned by the Trust (the
"Royalty"). Production figures provided in this letter and in the Trustee's
Discussion and Analysis are based on information provided by Burlington
Resources Oil & Gas Company LP ("BROG").

The Trust was established in November 1980 by Southland Royalty Company
("Southland Royalty"). Pursuant to the Indenture that governs the operations of
the Trust, Southland Royalty conveyed to the Trust a 75% net overriding royalty
interest (equivalent to a net profits interest) carved out of Southland's oil
and gas leasehold and royalty interests in properties in the San Juan Basin of
northwestern New Mexico. The Royalty is the principal asset of the Trust.

Under the Trust Indenture, TexasBank (successor trustee) as Trustee, has the
primary function of collecting monthly net proceeds ("Royalty Income")
attributable to the Royalty and making the monthly distributions to the Unit
holders after deducting administrative expenses and any amounts necessary for
cash reserves.

Income distributed to Unit holders from February through December 2002 was
$36,417,967 or $0.781354 per Unit. Distributable income for 11 months of 2002
consisted of Royalty Income of $38,053,281 plus interest income of $16,112, less
administrative expenses of $1,728,187, plus a reduction in cash reserves of
$76,761. The Trustee did not receive royalty income for January 2002 because
revenues based on production during the month of November 2001 were less than
expenses. Interest income of $150 received in January was added to cash
reserves.

On January 2, 1996, Southland Royalty was merged with and became a wholly owned
subsidiary of Meridian Oil, Inc. Subsequent to the merger, Meridian changed its
name to Burlington Resources Oil & Gas Company LP.

Information about the Trust's estimated proved reserves of gas, including coal
seam gas, and of oil as well as the present value of net revenues discounted at
10% can be found in Item 2 of the accompanying Form 10-K.

Certain Royalty Income is generally considered portfolio income under the
passive loss rules enacted by the Tax Reform Act of 1986. Therefore, it appears
that Unit holders should not consider the taxable income from the Trust to be
passive income in determining net passive income or loss.

Unit holders should consult their tax advisors for further information. Unit
holders of record will continue to receive an individualized tax information
letter for each of the quarters ending March 31, June 30 and September 30, 2003,
and for the year ending December 31, 2003. Unit holders owning Units in nominee
name may obtain monthly tax information from the Trustee upon request.

For readers' convenience, a glossary, which contains definitions, can be found
on the inside back cover. Please visit our Web site at www.sjbrt.com to access
news releases, reports, SEC filings and tax information.

TexasBank, Trustee

By: /s/ Lee Ann Anderson
Lee Ann Anderson
Vice President and Trust Officer

                                       2
<PAGE>

                                   [PICTURE]

If you can't stand the heat, well, maybe you're not a real chile chomper.
Fieriness is rated by Scoville Units, named for the pharmacist who first
measured Capsicum, the chemical in peppers that translates to heat. From mild
Poblanos to scorching Habaneros, Pequins or Thai peppers, there's a variety of
Capsicum for every taste. A rule of thumb: The smaller the chile, the hotter
the bite. Mouth on fire? Try milk or ice cream -- not water or soda -- to douse
the flames.

                                       3
<PAGE>

                                   [PICTURE]

Since the Spanish first planted chiles in the fertile Rio Grande valley in the
early 1600s, locals have touted their medicinal as well as culinary properties.
It seems the same chemical responsible for bringing tears to a chile eater's
eyes has equally impressive powers to heal. That's why many a hangover has been
tempered by menudo, a zesty soup made from beef tripe and pig's foot. And why
dipping into a pungent salsa is a sure-fire way to clear a stuffy head -- or at
least make the sufferer temporarily forget about it.

                                       4
<PAGE>


                         DESCRIPTION OF THE PROPERTIES

The principal asset of the Trust is a 75% net overriding royalty interest carved
out of certain working, royalty and other interests owned by BROG (the
"Underlying Interests") in properties located in the San Juan Basin, and more
particularly in San Juan, Rio Arriba and Sandoval Counties of northwestern New
Mexico (the "Underlying Properties"). The Underlying Properties contain 151,900
gross (119,000 net) producing acres and 3,738 gross (1,135 net) producing wells,
including dual completions.

     The Underlying Properties have historically produced gas primarily from
conventional wells drilled to three major formations: the Pictured Cliffs, the
Mesaverde and the Dakota, ranging in depth from 1,500 to 8,000 feet. The
characteristics of these reservoirs result in the wells having very long
productive lives. A production index for oil and gas properties is the number of
years derived by dividing remaining reserves by current production. Based upon
the reserve report prepared by the Trust's independent petroleum engineers as of
December 31, 2002, the production index for the San Juan Basin properties is
estimated to be approximately 9.47 years. The production index is subject to
change from year to year based on reserve revisions and production levels. Among
the factors considered by the Trust's engineers in estimating remaining reserves
of natural gas is the current sales price for gas. As the sales price increases,
the producer can justify expending higher lifting costs and therefore reasonably
expect to recover more of the known reserves. Accordingly, as gas prices rise,
the production index increases and vice versa.

     In February 2002, BROG informed the Trust that the New Mexico Oil
Conservation Division (the "OCD") had approved plans for 80-acre infill drilling
of the Dakota formation in the San Juan Basin. In October 2002, the OCD approved
a reduction from 320- to 160-acre spacing for those portions of the Fruitland
Coal formation where wells typically produce less than two MMcf per day. The OCD
has asked BROG and other interested parties to study over the next year whether
the change in spacing requirements should be expanded to cover other portions of
that reservoir.

     The process of removing coal seam gas is often referred to as
degasification or desorption. Millions of years ago, natural gas was generated
in the process of coal formation and absorbed into the coal. Water later filled
the natural fracture system. When the water is removed from the natural fracture
system, reservoir pressure is lowered and the gas desorbs from the coal. The
desorbed gas then flows through the fracture system and is produced at the well
bore. The volume of formation water production typically declines with time and
the gas production may increase for a period of time before starting to decline.
In order to dispose of the formation water, surface facilities including pumping
units are required, which results in the cost of a completed well being as much
as $500,000. During 2002, these coal seam wells produced a total of
approximately 11,133,332 MMBtu of gas from the Underlying Properties, which was
sold at an average price of $2.07 per MMBtu.

     Production from coal seam wells drilled prior to January 1, 1993, qualifies
for federal income tax credits through 2002. Thus, under current law, coal seam
gas production after December 31, 2002, will not qualify for the Section 29
credit. For 2001, the credit was approximately $1.08 per MMBtu. For 2002, the
amount of the credit will be determined by the Treasury Department no later than
April 1, 2003, and, based on historical trends, is expected to approximate
(within a 2-3% range) the 2001 credit. During 2001, potential Section 29 tax
credits of approximately $.117920 per Unit were generated for Unit holders from
production from coal seam wells.

     In February 2002, BROG announced an estimated capital budget for the
Underlying Properties of $17.1 million. During the year the estimate was
initially reduced to $12.4 million and ultimately increased to $19.0 million.
BROG's capital plan for the Underlying Properties for 2002 estimated 397
projects, including the drilling of 54 new wells operated by BROG and 26 wells
operated by third parties. In 2002, BROG actually participated in 339 projects,
including 41 new wells operated by BROG and 12 wells operated by third parties.
BROG reported that the swings in the budget estimates related in large part to
whether and when BROG was successful in obtaining the necessary governmental and
landowner approvals to drill on a well-by-well basis.

     The aggregate capital expenditures reported by BROG in calculating
distributable income for 2002 include approximately $10.1 million attributable
to the capital budgets for prior years. This occurs because projects within a
given year's budget may extend into subsequent years, with capital expenditures
attributable to those projects used in calculating distributable income to the
Trust in those subsequent years. Further, BROG's accounting period for capital
expenditures runs through November 30 of each calendar year, such that capital
expenditures incurred in December of each year are actually accounted for as
part of the following year's capital expenditures. Also, for wells not operated
by BROG, BROG's share of capital expenditures may not actually be paid by it
until the year or years after those expenses were incurred by the operator.
Capital expenditures of approximately $11.4 million for 2002 budgeted projects
were used in calculating distributable income in calendar year 2002, and
approximately

                                       5
<PAGE>

                         DESCRIPTION OF THE PROPERTIES

$3.6 million in capital expenditures was used in calculating distributions for
the first three months of 2003. Therefore, an additional approximately $4.0
million in capital expenditures for 2002 projects remains to be spent.

     During 2002, in calculating the net proceeds to the Trust, BROG deducted
approximately $21.5 million of capital expenditures for projects, including
drilling and completion of 98 gross (30.05 net) conventional wells, recompletion
of 36 gross (14.44 net) conventional wells, 13 gross (2.21 net) miscellaneous
capital projects, 1 gross (.82 net) restimulation, 1 gross (.05 net) payadd, 16
gross (5.42 net) coal seam wells, 11 gross (1.45 net) miscellaneous coal seam
capital projects, 14 gross (5.77 net) coal seam recompletions, 5 gross (.98 net)
coal seam recavitations, 3 gross (.01 net) coal seam restimulations and
facilities maintenance. There were 61 gross (24.49 net) new conventional wells,
20 gross (4.69 net) conventional well recompletions, 65 gross (19.82 net)
miscellaneous conventional capital projects, 4 gross (1.41 net) coal seam wells,
2 gross (.99 net) coal seam recompletions, and 5 gross (1.72 net) miscellaneous
coal seam capital projects in progress as of December 31, 2002.

     During 2001, in calculating the net proceeds to the Trust, BROG deducted
approximately $33 million of capital expenditures for projects, including
drilling and completion of 92 gross (36.33 net) conventional wells, recompletion
of 33 gross (18.18 net) conventional wells, 13 gross (2.85) net miscellaneous
capital projects, 3 gross (2.34 net) restimulations, 56 gross (8.40 net)
conventional payadds, 10 gross (1.52 net) coal seam wells, 4 gross (1.61 net)
coal seam recompletions, 1 gross (.88 net) coal seam payadd, 6 gross (.04 net)
coal seam recavitations and facilities maintenance. There were 100 gross (32.47
net) new conventional wells, 31 gross (13.47 net) conventional well
recompletions, 2 gross (.87 net) miscellaneous conventional capital projects, 9
gross (3.17 net) conventional payadds, 15 gross (1.09 net) conventional
restimulations, 12 gross (5.36 net) coal seam wells, 7 gross (4.11 net) coal
seam recompletions, 2 gross (.02 net) coal seam restimulations and 6 gross (.29
net) miscellaneous coal seam capital projectsin progress as of December 31,
2001.

     For 2003, BROG's announced plan for the Underlying Properties includes 351
projects at an aggregate cost of $14.1 million. Approximately $10.6 million of
that budgetis allocable to new wells, with approximately 41% of those wells
projected to be drilled to formations producing coal seam gas as distinguished
from conventional gas. BROG reports that based on its actual capital
requirements, its mix of projects and swings in the price of natural gas, the
actual capital expenditures for 2003 could range from $10 million to $22
million. In August 2002, the New Mexico Oil Conservation Division approved
reduced, 160-acre spacing in selected portions of the Fruitland Coal formation.
BROG has indicated that, principally as a result of that decision, its budget
for 2003 reflects a focus on the Fruitland Coal formation.

     BROG has previously informed the Trust that increases in its capital
program, particularly in 2000 and 2001, were designed to offset the natural
decline in production from the Underlying Properties. BROG has reported
favorable results in this effort in that natural gas production for calendar
year 2002 averaged approximately 127 MMcf per day, as compared to average
production of approximately 121 MMcf per day for calendar 2001 and 116 MMcf per
day for calendar 2000.

     BROG indicates its budget for 2003 reflects continued significant
development of properties in which the Trust's net overriding royalty interest
is relatively high, sustained focus on conventional formations, including infill
drilling to the Mesaverde and Dakota formations, development of the Fruitland
Coal formation and multiple formation completions.

     The Federal Energy Regulatory Commission is primarily responsible for
federal regulation of natural gas. For a further discussion of gas pricing, gas
purchasers, gas production and regulatory matters affecting gas production see
Item 2, "Properties," in the accompanying Form 10-K.


                                    [GRAPH]


                                       6
<PAGE>
                       TRUSTEE'S DISCUSSION AND ANALYSIS

Distributable Income consists of Royalty Income plus interest, less the general
and administrative expenses of the Trust and any changes in cash reserves
established by the Trustee. For the year ended December 31, 2002, Distributable
Income decreased to $36,417,967 from $80,126,202 distributed in 2001. The
decrease was primarily attributable to lower gas and oil prices and to the loss
of the Val Verde Credit (as defined and described below), offset in part by the
effect of audit exceptions identified by the Trust's joint interest auditors and
granted and paid by BROG in the third quarter.

     Interest income decreased from $165,676 in 2001 to $16,112 in 2002,
primarily due to lower interest rates and decreased funds available to invest.

     Total gas and oil production from the Underlying Properties for the five
years ended December 31, 2002, were as follows:

<Table>
<Caption>
                         2002           2001           2000           1999           1998
                      ----------     ----------     ----------     ----------     ----------
<S>                   <C>            <C>            <C>            <C>            <C>
Gas -- Mcf ......     46,206,297     42,960,149     42,220,260     39,940,175     41,507,353
Mcf per Day .....        126,593        117,699        115,356        109,425        113,719
Oil -- Bbls .....         93,659         92,413         97,330         72,223         81,888
Bbls per Day ....            257            253            266            198            224
</Table>

     Sales volumes attributable to the Royalty are determined by dividing the
net profits received by the Trust and attributable to oil and gas, respectively,
by the prices received for sales volumes from the Underlying Properties, taking
into consideration production taxes attributable to the Underlying Properties.
Since the oil and gas sales attributable to the Royalty are based on an
allocation formula dependent on such factors as price and cost, including
capital expenditures, the aggregate sales amounts from the Underlying Properties
may not provide a meaningful comparison to sales attributable to the Royalty.

    Royalty Income for the calendar year is associated with actual gas and oil
production during the period from November of the preceding year through October
of the current year. Gas and oil sales attributable to the Royalty for the past
five years are summarized in the following table:

<Table>
<Caption>
                                     2002             2001             2000             1999             1998
                                  ----------       ----------       ----------       ----------       ----------
<S>                               <C>              <C>              <C>              <C>              <C>
Gas -- Mcf ................       19,584,056       19,272,021       20,317,750       19,527,666       18,904,906
Average Price (per Mcf) ...            $2.32            $4.61            $2.99            $1.78            $1.75
Oil -- Bbls ...............           40,215           42,056           47,441           35,341           37,067
Average Price (per Bbl) ...           $20.90           $24.99           $24.66           $14.41           $13.55
</Table>


The fluctuations in annual gas production that have occurred during these five
years generally resulted from changes in the demand for gas during that time,
marketing conditions, and increased capital spending to generate production from
new wells. Production from the Underlying Properties is influenced by the line
pressure of the gas gathering systems in the San Juan Basin. As noted above, oil
and gas sales attributable to the Royalty are based on an allocation formula
dependent on many factors, including oil and gas prices and capital
expenditures.

                                       7
<PAGE>
                       TRUSTEE'S DISCUSSION AND ANALYSIS

Royalty Income for the five years ended December 31, 2002, was determined as
shown in the following table:

<Table>
<Caption>
                                              2002                  2001              2000              1999              1998
                                          -------------         ------------      ------------      ------------       -----------
<S>                                       <C>                   <C>               <C>               <C>                <C>
Gross Proceeds from
the Underlying Properties:
--------------------------
Gas .................................     $ 103,349,299         $169,052,231      $124,902,689      $ 69,928,312       $71,247,501
Oil .................................         1,863,827            2,233,071         2,409,158         1,028,862         1,088,228
Other ...............................        (5,110,589)(1)              -0-         4,653,333         1,189,996               -0-
                                          -------------         ------------      ------------      ------------       -----------
   Total ............................     $ 100,102,537         $171,285,302      $131,965,180      $ 72,147,170       $72,335,729
                                          =============         ============      ============      ============       ===========

Less Production Costs:
----------------------
Capital Costs .......................        21,470,777           32,999,973        25,575,657        10,556,159        12,828,300
Severance Tax -- Gas ................         9,752,508           16,687,074        12,059,286         7,180,973         7,341,098
Severance Tax -- Oil ................           151,594              202,113           234,462           106,335           117,454
Other ...............................            18,037               55,000           129,161           (95,445)           66,892
Lease Operating Expenses ............        15,701,740           15,109,139        13,906,916        10,896,526        11,558,172
                                          -------------         ------------      ------------      ------------       -----------
   Total ............................        47,094,656           65,053,299        51,905,482        28,644,548        31,911,916
                                          -------------         ------------      ------------      ------------       -----------
Excess Production Costs .............        (2,259,628)           2,259,628               -0-               -0-               -0-
Interest on Excess Production Costs .           (10,545)                 -0-               -0-               -0-               -0-
Net Profits .........................        50,737,708          108,491,631        80,059,698        43,502,622        40,423,813
Royalty Percentage ..................                75%                  75%               75%               75%               75%
Royalty Income ......................     $  38,053,281         $ 81,368,723      $ 60,044,773      $ 32,626,966       $30,317,860
                                          =============         ============      ============      ============       ===========
</Table>


(1)  Represents deductions by BROG from the net proceeds otherwise payable to
     the Trust in connection with the portion of various settlement agreements
     with the Mineral Management Service of the United States Department of
     Interior allocable to the Royalty (see Item 3 of Trust's Annual Report on
     Form 10-K).

     Included in the 2000 distributable income was a payment by BROG to the
Trust in June 2000 of $3,490,000. In June 2000, the Trust and BROG entered into
a partial settlement of a claim relating to a gas imbalance. A gas imbalance
occurs when more than one party is entitled to the economic benefit of the
production of natural gas, but the gas is sold for the account of less than all
the parties. Under the terms of the partial settlement, BROG paid the Trust
$3,490,000 to settle the imbalance insofar as it relates to some of the wells
located on the subject properties. BROG has indicated that the remainder of the
imbalance is to be addressed through volume adjustments whereby the Trust's net
overriding royalty interest will be applied to 50% of the overproduced parties'
interest on a monthly basis, until the imbalance is corrected. The Trust is in
communication with BROG in order to determine the estimated value of the volume
adjustments and the time during which the remainder of the imbalance will be
corrected.

     Included in 1999 Distributable Income was a payment by BROG to the Trust in
March 1999 of $892,498. After a rupture of the Williams "Trunk S" Pipeline
disrupted a significant flow of gas from BROG properties, BROG filed claims with
insurance carriers and subsequently received payments of its claims. Some of the
claims filed related to properties burdened by the Royalty. The amount of
insurance proceeds applicable to such properties was determined to be
$1,189,996, of which the Trust received 75% or $892,498.

     Based on its 1999 year-end review, BROG determined that it had undercharged
the Trust for both capital expenditures and lease operating charges related to
properties burdened by the Trust but not operated by BROG. In April and May of
2000, BROG passed through to the Trust additional charges of $652,303 in capital
expenditures and $1,689,509 in lease operating charges related to the
undercharged non-operated properties. The Trust's consultants have reviewed
BROG's cost reporting data and confirmed that these additional charges were
appropriate.

     Operating expenses for 1998 through 2001 include the impact of the receipt
of $250,000 from BROG as an offset to lease operating expense in connection with
the settlement of the litigation described in Note 5 to the accompanying
Financial Statements. The final $250,000 offset was made in December 2001.
Monthly lease operating costs in 2002 averaged approximately $1,262,913, which
is higher than the $1,242,247 average in 2001. For additional information on
capital expenditures, see "Description of the Properties."

     As part of the September 4, 1996, settlement of the litigation

                                        8
<PAGE>

filed by the Trustee on June 4, 1992, against BROG and Southland Royalty
Company, the Trust was entitled to certain adjustments (the "Val Verde Credit")
that represented cost reductions favorable to the Trust in the charges for coal
seam gas gathered and treated on BROG's Val Verde system. The settlement
provided that the Val Verde Credit was applicable until the later of July 1,
2002, or until BROG no longer owned the Val Verde facility. By correspondence
dated July 15, 2002, BROG notified the Trustee of the sale of the Val Verde
facility to TEPPCO Partners, L.P. effective July 1, 2002. Accordingly, effective
July 1, 2002, the calculation of net proceeds for gas gathered and treated at
the Val Verde facility no longer included the Val Verde Credit. The total amount
of the Val Verde Credit for the twelve months ended June 30, 2002, was estimated
by the Trust's joint interest auditors as approximately $1,880,000. The loss of
the Val Verde Credit will result in increased costsallocated to the Trust for
coal seam gas gathered and treated on the Val Verde system and accordingly, will
decrease Royalty Income.

     The current war in Iraq has increased the volatility in prices for oil and
gas. It is unclear what effect the current war in Iraq will have on the net
proceeds received by the Trust and, accordingly, Distributable Income.

CONTRACTUAL OBLIGATIONS

Under the Trust's indenture, the Trustee is entitled to an administrative fee
for its administrative services and the preparation of quarterly and annual
statements 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. Beginning January 1, 2003, in no case will the
administrative fee due under items (i) and (ii) above be less than $36,000 per
year (as adjusted annually to reflect the increase (if any) in the Producers
Price Index as published by the U.S. Department of Labor, Bureau of Labor
Statistics).

EFFECTS OF SECURITIES REGULATION

As a publicly-traded trust listed on the New York Stock Exchange (the "NYSE"),
the Trust is and will continue to be subject to extensive regulation under,
among others, the Securities Act of 1933, the Exchange Act of 1934, the rules
and regulations of the NYSE and the Sarbanes-Oxley Act of 2002. Issuers failing
to comply with such authorities risk serious consequences, including criminal as
well as civil and administrative penalties. In most instances, these laws, rules
and regulations do not specifically address their applicability to
publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act
of 2002 provides for the adoption by the Securities and Exchange Commission (the
"Commission") of certain rules and regulations that may be impossible for the
Trust to literally satisfy because of its nature as a pass-through trust. For
example, the Commission is required to adopt rules and regulations pursuant to
the Sarbanes-Oxley Act of 2002 that would require a publicly-traded company's
board of directors, audit committee or executive directors (or similar body) to
act with respect to certain corporate governance matters. The Trust does not
have, nor does the indenture governing the Trust provide for, a board of
directors, an audit committee or any executive officers. Accordingly, the Trust
could not literally comply with such rules and regulations. It is the Trustee's
intention to follow the Commission's rulemaking closely, attempt to comply with
such rules and regulations and, where appropriate, request relief from these
rules and regulations. However, if the Trust is unable to comply with such rules
and regulations or to obtain appropriate relief, the Trust may be required to
expend as yet unknown but potentially material costs to amend the indenture that
governs the Trust to allow for compliance with such rules and regulations.

CRITICAL ACCOUNTING POLICIES

In accordance with the Commission's staff accounting bulletins and consistent
with other royalty trusts, the financial statements of the Trust are prepared on
the following basis:

     o    Royalty Income recorded for a month is the amount computed and paid by
          BROG to the Trustee for the Trust.

     o    Trust expenses recorded are based on liabilities paid and cash
          reserves established from Royalty Income for liabilities and
          contingencies.

     o    Distributions to Unit holders are recorded when declared by the
          Trustee.

     o    The conveyance which transferred the Royalty to the Trust provides
          that any excess of production costs over gross proceeds must be
          recovered from future net profits.

     The financial statements of the Trust differ from financial statements
prepared in accordance with U.S. generally accepted accounting principles
("GAAP") because revenues are not accrued in the month of production; certain
cash reserves may be established for contingencies which would not be accrued in
financial statements prepared in accordance with GAAP; and amortization of the
Royalty calculated on a unit-of-production basis is charged directly to trust
corpus instead of an expense.

                                       9
<PAGE>


                  RESULTS OF THE 4TH QUARTER OF 2002 AND 2001

For the three months ended December 31, 2002, Distributable Income was
$11,579,818 ($.248447 per Unit), which was more than the $2,898,013 ($.062177
per Unit) of income distributed during the same period in 2001. The increase in
Distributable Income resulted primarily from higher average gas and oil prices,
and decreased capital costs compared to the fourth quarter of 2001.

     Royalty Income of the Trust for the fourth quarter is associated with
actual gas and oil production during August through October of each year. Gas
and oil sales for the quarters ended December 31, 2002 and 2001 were as follows:


<Table>
<Caption>
Underlying Properties                 2002           2001
---------------------              ----------     ----------
<S>                                <C>            <C>
Gas -- Mcf ...................     11,608,135     10,248,195
   Average Price (per Mcf) ...          $2.30          $1.87
Oil -- Bbls ..................         19,624         21,018
   Average Price (per Bbl) ...         $23.61         $20.88

Attributable to the Royalty
---------------------------
Gas -- Mcf ...................      5,574,600      1,483,888
Oil -- Bbls ..................          9,184          2,792
</Table>


     The average price of gas and oil increased in the fourth quarter of 2002
compared to the same period in the prior year. The price per barrel of oil
during the fourth quarter of 2002 was $2.73 per Bbl higher than that received in
the fourth quarter of 2001 due to increases in oil prices in world markets
generally, including the posted price applicable to the Royalty. Gas production
increased slightly in the fourth quarter of 2002 as compared with the same
period in 2001 primarily due to increased demand. During the fourth quarter of
2002, coal seam production from the Underlying Properties averaged 1,413,871 Mcf
per month compared to 961,310 Mcf per month during the fourth quarter of 2001.

     Capital costs for the fourth quarter of 2002 totaled $4,653,069 compared to
$11,528,106 during the same period of 2001. The decrease was primarily due to
decreased drilling activity in the fourth quarter of 2002 as compared to the
same period in 2001. Lease operating expenses and property taxes for the fourth
quarter of 2002 averaged $1,322,655 per month compared to $1,411,550 per month
in the fourth quarter of 2001.


                                       10
<PAGE>

                          SAN JUAN BASIN ROYALTY TRUST

Statements of Assets, Liabilities and Trust Corpus
December 31, 2002 and 2001

<Table>
<Caption>
Assets                                                            2002            2001
------                                                         -----------     -----------
<S>                                                            <C>             <C>
Cash and Short-term Investments ..........................     $ 4,274,790     $   191,620
Net Overriding Royalty Interests in Producing
   Oil and Gas Properties ................................      33,697,906      37,859,749
                                                               -----------     -----------
                                                               $37,972,696     $38,051,369
                                                               ===========     ===========

Liabilities and Trust Corpus
----------------------------
Distribution Payable to Unit Holders .....................     $ 4,159,932     $       -0-
Cash Reserves ............................................         114,858         191,620
Trust Corpus -- 46,608,796 Units of Beneficial Interest
   Authorized and Outstanding ............................      33,697,906      37,859,749
                                                               -----------     -----------
                                                               $37,972,696     $38,051,369
                                                               ===========     ===========
</Table>


Statements of Distributable Income
for the Three Years Ended December 31, 2002

<Table>
<Caption>
                                                              2002             2001            2000
                                                         ------------      -----------     -----------
<S>                                                      <C>               <C>             <C>
Royalty Income .....................................     $ 38,053,281      $81,368,723     $60,044,773
Interest Income ....................................           16,112          165,676         148,513
                                                         ------------      -----------     -----------
                                                           38,069,393       81,534,399      60,193,286
Expenditures -- General and Administrative .........        1,728,187        1,216,577       1,004,354
Change in Cash Reserves ............................          (76,761)         191,620             -0-
Distributable Income ...............................     $ 36,417,967      $80,126,202     $59,188,932
                                                         ============      ===========     ===========
Distributable Income Per Unit (46,608,796 units) ...     $   0.781354      $  1.719123     $  1.269909
                                                         ============      ===========     ===========
</Table>


Statements of Changes in Trust Corpus
for the Three Years Ended December 31, 2002

<Table>
<Caption>
                                                              2002              2001              2000
                                                          ------------      ------------      ------------
<S>                                                       <C>               <C>               <C>
Trust Corpus, Beginning of Period ...................     $ 37,859,749      $ 40,686,854      $ 45,186,199
   Amortization of Net Overriding Royalty Interest ..       (4,161,843)       (2,827,105)       (4,499,345)
   Distributable Income .............................       36,417,967        80,126,202        59,188,932
   Distribution Declared ............................      (36,417,967)      (80,126,202)      (59,188,932)
                                                          ------------      ------------      ------------
Trust Corpus, End of Period .........................     $ 33,697,906      $ 37,859,749      $ 40,686,854
                                                          ============      ============      ============
</Table>

The accompanying Notes to Financial Statements are an integral part of these
statements.


                                       11
<PAGE>

           SAN JUAN BASIN ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS

1. TRUST ORGANIZATION AND PROVISIONS

The San Juan Basin Royalty Trust ("Trust") was established as of November 1,
1980. As of September 30, 2002, TexasBank ("Trustee") replaced Bank One, N.A.,
as Trustee for the Trust. Southland Royalty Company ("Southland") conveyed to
the Trust a 75% net overriding royalty interest ("Royalty") carved out of
Southland's working interests and royalty interests in the properties located in
the San Juan Basin in northwestern New Mexico (the "Underlying Properties").

     On November 3, 1980, units of beneficial interest ("Units") in the Trust
were distributed to the Trustee for the benefit of Southland shareholders of
record as of November 3, 1980, who received one Unit in the Trust for each share
of Southland common stock held. The Units are traded on the New York Stock
Exchange.

     The terms of the Trust Indenture provide, among other things, that:

     o    The Trust shall not engage in any business or commercial activity of
          any kind or acquire any assets other than those initially conveyed to
          the Trust;

     o    The Trustee may not sell all or any part of the Royalty unless
          approved by holders of 75% of all Units outstanding, in which case the
          sale must be for cash and the proceeds promptly distributed;

     o    The Trustee may establish a cash reserve for the payment of any
          liability which is contingent or uncertain in amount;

     o    The Trustee is authorized to borrow funds to pay liabilities of the
          Trust; and

     o    The Trustee will make monthly cash distributions to Unit holders (see
          Note 2).

2. NET OVERRIDING ROYALTY INTEREST AND DISTRIBUTION TO UNIT HOLDERS

The amounts to be distributed to Unit holders ("Monthly Distribution Amounts")
are determined on a monthly basis. The Monthly Distribution Amount is an amount
equal to the sum of cash received by the Trustee during a calendar month
attributable to the Royalty, any reduction in cash reserves and any other cash
receipts of the Trust, including interest, reduced by the sum of liabilities
paid and any increase in cash reserves. If the Monthly Distribution Amount for
any monthly period is a negative number, then the distribution will be zero for
such month and such negative amount will be carried forward and deducted from
future monthly distributions until the cumulative distribution calculation
becomes a positive number, at which time a distribution will be made. Unit
holders of record will be entitled to receive the calculated Monthly
Distribution Amount for each month on or before ten business days after the
monthly record date, which is generally the last business day of each calendar
month.

     The cash received by the Trustee consists of the amounts received by the
owner of the interest burdened by the Royalty from the sale of production less
the sum of applicable taxes, accrued production costs, development and drilling
costs, operating charges and other costs and deductions, multiplied by 75%.

     The initial carrying value of the Royalty ($133,275,528) represented
Southland's historical net book value at the date of the transfer of the Trust.
Accumulated amortization as of December 31, 2002 and 2001 aggregated $99,577,622
and $95,415,779 respectively.

3. BASIS OF ACCOUNTING

     The financial statements of the Trust are prepared on the following basis:

     o    Royalty income recorded for a month is the amount computed and paid by
          the working interest owner, Burlington Resources Oil and Gas Company
          LP ("BROG"), to the Trustee for the Trust. Royalty income consists of
          the amounts received by the owner of the interest burdened by the net
          overriding royalty interest from the sale of production less accrued
          production costs, development and drilling costs, applicable taxes,
          operating charges, and other costs and deductions, multiplied by 75%.

     o    Trust expenses recorded are based on liabilities paid and cash
          reserves established from Royalty income for liabilities and
          contingencies.

     o    Distributions to Unit holders are recorded when declared by the
          Trustee.

     o    The conveyance which transferred the overriding royalty interest to
          the Trust provides that any excess of production costs over gross
          proceeds must be recovered from future net profits. The financial
          statements of the Trust differ from financial statements prepared in
          accordance with U.S. generally accepted accounting principles ("GAAP")
          because revenues are not accrued in the month of production; certain
          cash reserves may be established for contingencies which would not be
          accrued in financial statements prepared in accordance with GAAP; and
          amortization of the Royalty calculated on a unit-of-production basis
          is charged directly to trust corpus instead of an expense.


                                       12
<PAGE>
4. FEDERAL INCOME TAXES

For federal income tax purposes, the Trust constitutes a fixed investment trust
which is taxed as a grantor trust. A grantor trust is not subject to tax at the
trust level. The Unit holders are considered to own the Trust's income and
principal as though no trust were in existence. The income of the Trust is
deemed to have been received or accrued by each Unit holder at the time such
income is received or accrued by the Trust rather than when distributed by the
Trust.

     The Royalty constitutes an "economic interest" in oil and gas properties
for federal income tax purposes. Unit holders must report their share of the
revenues of the Trust as ordinary income from oil and gas royalties and are
entitled to claim depletion with respect to such income. The Royalty is treated
as a single property for depletion purposes.

     The Trust has on file technical advice memoranda confirming the tax
treatment described above.

     The Trust began receiving royalty income from coal seam gas wells in 1989.
Under Section 29 of the Internal Revenue Code, coal seam gas production from
wells drilled prior to January 1, 1993 (including certain wells recompleted in
coal seam formations thereafter) generally qualifies for the federal income tax
credit for producing nonconventional fuels if such production and the sale
thereof occurs before January 1, 2003. Under current law, coal seam gas
production after December 31, 2002, will not qualify for the Section 29 credit.
For 2001, this tax credit was approximately $1.08 per MMBtu. For 2002, the
amount of the credit will be determined by the Treasury Department no later than
April 1, 2003, and, based on historical trends, is expected to approximate
(within a 2-3% range) the 2001 credit. The Trust also receives production from
wells producing from a tight sands formation. These wells must have been drilled
after November 5, 1990, or must have been committed or dedicated to interstate
commerce (as defined in Section 2(18) of the Natural Gas Policy Act as in effect
November 5, 1990) as of April 20, 1977. This credit is not adjusted for
inflation, so the credit remains fixed at .517241 per MMBtu. For qualifying
production of the Trust, each Unit holder must determine from the tax
information they receive from the Trust, his pro rata share of qualifying
production of the Trust, based upon the number of Units owned during each month
of the year, and the amount of available credit per MMBtu for the year, and
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.

     The Trustee is provided summary Section 29 tax credit information related
to Trust properties by BROG, which information is then passed along to the Unit
holders. In 1999, the U.S. Court of Appeals for the 10th Circuit upheld the
position of the Internal Revenue Service and the Tax Court that nonconventional
fuel such as coal seam gas does not qualify for the Section 29 credit unless the
producer has received an appropriate well category determination from the
Federal Energy Regulatory Commission ("FERC"). The FERC's certification
authority expired effective January 1, 1993. However, on July 14, 2000, the FERC
issued a final ruling amending its regulations to reinstate certain regulations
involving well category determinations for all wells and tight formation areas
that could qualify for the Section 29 tax credit. BROG has informed the Trustee
that it will seek certification of all qualified wells and that two additional
wells were certified in 2002. The classification of the Trust's income for
purposes of the passive loss rules may be important to a Unit holder. As a
result of the Tax Reform Act of 1986, royalty income will generally be treated
as portfolio income and will not reduce passive losses.

5. LITIGATION SETTLEMENT

On September 4, 1996, the Trustee announced the settlement of litigation between
the Trust and BROG. In the settlement, BROG agreed (i) to pay $19,750,000 in
cash plus interest earning 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 that
will provide the Trustee and its representatives improved access to BROG's books
and records applicable to the Underlying Properties. The final $250,000 payment
was received in 2001. In addition, BROG sold the Val Verde gathering system in
2002, thus increasing costs to the Trust.

     Agreement was also reached regarding marketing arrangements for the sale of
gas, oil and natural gas liquids products

                                       13
<PAGE>

from the Underlying Properties going forward as follows:

     1. BROG agreed that contracts for the sale of gas from the Underlying
Properties would require the written approval of an independent gas marketing
consultant acceptable to the Trust. For a
discussion of the current contract covering the sale of gas from the Underlying
Properties, see Note 6.

     2. BROG will continue to market the oil and natural gas liquids from the
Underlying Properties 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.

     3. The Trust retained access to BROG's current gas trans-portation,
gathering, processing and treating agreements with third parties through the
remainder of their primary terms.

6. CERTAIN CONTRACTS

BROG entered into a contract dated November 10, 1999, for the sale of all
volumes of Trust gas to Duke Energy and Marketing L.L.C. That contract, as
amended, provided for delivery of gas at various delivery points over a period
commencing January 1, 2000, and ending March 31, 2002. BROG has subsequently
entered into two contracts for the sale of all volumes of gas which are subject
to the Royalty. These contracts provide for (i) the sale of Trust gas in two
packages to Duke Energy and Marketing L.L.C. and PNM Gas Services, respectively,
(ii) the delivery of Trust gas at various delivery points over a period
commencing April 1, 2002, and ending March 31, 2004, and (iii) the sale of Trust
gas at prices which fluctuate in accordance with published indices for gas sold
in the San Juan Basin of New Mexico.

     Confidentiality agreements with purchasers of gas produced from the
Underlying Properties prohibit public disclosure of certain terms and conditions
of gas sales contracts with those entities, including specific pricing terms,
gas receipt points, etc. Such disclosure could compromise the ability to compete
effectively in the marketplace for the sale of gas produced from the Underlying
Properties.

7. GAS IMBALANCE

In June 2000, the Trust and BROG entered into a partial settlement of claims
relating to a gas imbalance with respect to production from mineral properties
currently operated by BROG. Under the terms of the partial settlement, BROG paid
the Trust $3,490,000 to settle the imbalance insofar as it relates to some of
the wells located on the subject properties. The remainder of the imbalance is
to be addressed through volume adjustments whereby the Trust's net overriding
royalty interest will be applied to 50% of the overproduced parties' interest,
on a monthly basis, until the imbalance is corrected. The Trust is in
communication with BROG in order to determine the estimated value of the volume
adjustments and the time during which the remainder of the imbalance will be
corrected.

8. PRIOR PERIOD ADJUSTMENTS

Based on its year-end review, BROG has determined that since January of 1999,
BROG has undercharged the Trust for both capital expenditures and lease
operating charges related to properties burdened by the Trust but not operated
by BROG. In April and May of 2000, BROG passed through to the Trust additional
charges of $652,303 in capital expenditures and $1,689,509 in lease operating
charges related to the under-charged non-operated properties. The Trust's
consultants have reviewed BROG's cost reporting data and confirmed that the
pass-through of these additional charges was appropriate.

9. CONTINGENCIES

Information regarding the status of litigation matters is included in Item 3 of
the Trust's annual report on Form 10-K which is included in this report.

10. COMMITMENTS AND CONTINGENCIES

At December 31, 2001, BROG had incurred excess production costs of $2,259,628 on
the Underlying Properties due primarily to high capital costs. The Trust
conveyance provides for the deduction of excess production costs in determining
royalty income until such costs are fully recovered and allows for interest to
be charged on excess production costs at the prime rate. Interest in the amount
of $10,545 was added to such excess production costs. Of the total, $1,702,630
is attributable to the Trust and has been deducted in determining 2002 royalty
income. As a result of settlements agreed to among BROG and other third parties
concerning properties burdened by the Royalty, the net profits applicable to the
Trust were reduced by approximately $3,624,117. This amount was deducted from
the Royalty due the Trust in one million dollar increments in each of May, June
and July of 2002, with the balance deducted in August of 2002.


                                       14
<PAGE>

11. SIGNIFICANT CUSTOMERS

Information as to significant purchasers of oil and gas production attributable
to the Trust's economic interests is included in Note 6 above and Item 2 of the
Trust's annual report on Form 10-K which is included in this report.

12. PROVED OIL AND GAS RESERVES (UNAUDITED)

Proved oil and gas reserve information is included in Item 2 of the Trust's
annual report on Form 10-K which is included in this report.

13. AMENDMENTS TO THE TRUST'S INDUSTRIES

At a special meeting of Unit holders on September 30, 2002, the Unit holders
appointed TexasBank as the successor Trustee of the Trust. The Unit holders also
approved amendments to the Trust's Royalty Trust Indenture (the "Indenture")
which clarified the language of the Indenture, clarified and expanded the
indemnification provisions of the Indenture, and amended the provisions of the
Indenture applicable to the fees payable to the Trustee, the investment options
available to the Trustee and the manner in which the Trustee can dispose of
assets of the Trust.

14. QUARTERLY SCHEDULE OF DISTRIBUTABLE INCOME (UNAUDITED)

The following is a summary of the unaudited quarterly schedule of distributable
income for the two years ended December 31, 2002 (in thousands, except unit
amounts):

<Table>
<Caption>
                                                Distributable
                                                  Income and
                        Royalty   Distributable  Distribution
2002                     Income      Income       Per Unit
----                   --------   ------------- -------------
<S>                    <C>          <C>          <C>
First Quarter ....     $  3,925     $  3,527     $ .075673
Second Quarter ...        9,560        9,015       .193414
Third Quarter ....       12,549       12,296       .263820
Fourth Quarter ...       12,019       11,580       .248447
                       --------     --------     ---------
   Total .........     $ 38,053     $ 36,418     $ .781354
                       ========     ========     =========

2001
----
First Quarter ....     $ 37,490     $ 37,262     $ .799474
Second Quarter ...       26,586       26,251       .563215
Third Quarter ....       13,972       13,715       .294257
Fourth Quarter ...        3,321        2,898       .062177
                       --------     --------     ---------
   Total .........     $ 81,369     $ 80,126     $1.719123
                       ========     ========     =========
</Table>


                                       15
<PAGE>


                          INDEPENDENT AUDITORS' REPORTS

TexasBank as Trustee for the San Juan Basin Royalty Trust:

We have audited the accompanying statements of distributable income and changes
in trust corpus of the San Juan Basin Royalty Trust ("Trust") for the year ended
December 31, 2000. These financial statements are the responsibility of the
Trustee. Our responsibility is to express an opinion on these financial
statements based on our audit.

     We conducted our audit in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statement. An audit also includes assessing the accounting principles used and
significant estimates made by the Trustee, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

     As described in Note 3 to the financial statements, these financial
statements were prepared on a modified cash basis, which is a comprehensive
basis of accounting other than accounting principles generally accepted in the
United States of America.

     In our opinion, such financial statements present fairly, in all material
respects, the distributable income and changes in trust corpus of the San Juan
Basin Royalty Trust for the year ended December 31, 2000, on the basis of
accounting described in Note 3.

/s/ DELOITTE & TOUCHE, L.L.P.
Deloitte & Touche, L.L.P.
Fort Worth, Texas
March 23, 2001


TexasBank as Trustee for the San Juan Basin Royalty Trust:

     We have audited the accompanying statements of assets, liabilities and
trust corpus of the San Juan Basin Royalty Trust as of December 31, 2002 and
2001, and the related statements of distributable income and changes in trust
corpus for the years then ended. These financial statements are the
responsibility of the Trustee. Our responsibility is to express an opinion on
these financial statements based on our audits.

     We conducted our audits in accordance with U.S. generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by the
Trustee, as well as evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.

     As described in Note 3 to the financial statements, these financial
statements were prepared on a modified cash basis of accounting, which is a
comprehensive basis of accounting other than U.S. generally accepted accounting
principles.

     In our opinion, such financial statements present fairly, in all material
respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty
Trust as of December 31, 2002 and 2001, and the distributable income and changes
in trust corpus for the years then ended, on the basis of accounting described
in Note 3 to the financial statements.


WEAVER AND TIDWELL, L.L.P.
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
March 24, 2003


San Juan Basin Royalty Trust
TexasBank, Trustee
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas 76116
Toll-free telephone: 866-809-4553
www.sjbrt.com
sjt@texasbank.com

Auditors
Weaver and Tidwell, L.L.P.
Fort Worth, Texas

Legal Counsel
Vinson & Elkins L.L.P.
Dallas, Texas

Tax Counsel
Winstead, Sechrest & Minick, PC
Houston, Texas

Transfer Agent
Computershare Investor Services
Transfer Services
P.O. Box A3480
Chicago, Illinois 60609-3480
For questions about distribution checks,
address changes and transfer procedures,
call 312-360-5154.

                                       16
<PAGE>
                               GLOSSARY OF TERMS

AGGREGATE MONTHLY DISTRIBUTION: An amount paid to Unit holders equal to the
Royalty Income received by the Trustee during a calendar month plus interest,
less the general and administrative expenses of the Trust, adjusted by any
changes in cash reserves.

BBL: Barrel, generally 42 U.S. gallons measured at 60 degrees F.

BCF: Billion cubic feet.

BROG: Burlington Resources Oil & Gas Company LP.

BTU: British thermal unit; the amount of heat necessary to raise the temperature
of one pound of water one degree Fahrenheit.

COAL SEAM WELL: A well completed to a coal deposit found to contain and emit
natural gas.

COMMINGLED WELL: A well which produces from two or more formations through a
common well casing and a single tubing string.

CONVENTIONAL WELL: A well completed to a formation historically found to contain
deposits of oil or gas (for example, in the San Juan Basin, the Pictured Cliffs,
Dakota and Mesaverde formations) and operated in the conventional manner.

DEPLETION: The exhaustion of a petroleum reservoir; the reduction in value of a
wasting asset by removing minerals; for tax purposes, the removal and sale of
minerals from a mineral deposit.

DISTRIBUTABLE INCOME: An amount paid to Unit holders equal to the royalty income
received by the Trustee during a given period plus interest, less the general
and administrative expenses of the Trust, adjusted by any changes in cash
reserves.

DUAL COMPLETION: The completion of a well into two separate producing formations
at different depths, generally through one string of pipe producing from one of
the formations, inside of which is a smaller string of pipe producing from the
other formation.

ESTIMATED FUTURE NET REVENUES: An estimate 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; sometimes referred to as
"estimated future net cash flows."

GRANTOR TRUST: A trust (or portion thereof) with respect to which the grantor or
an assignee of the grantor, rather than the trust, is treated as the owner of
the trust properties and is taxed directly on the trust income for federal
income tax purposes under Sections 671 through 679 of the Internal Revenue Code.

GROSS ACRES OR WELLS: The interests of all persons owning interests in such
acres or wells.

GROSS PROCEEDS: The amount received by BROG (or any subsequent owner of the
Underlying Interests) from the sale of the production attributable to such
interests.

INFILL DRILLING: The drilling of wells intended to be completed to proven
reservoirs or formations, sometimes occurring in conjunction with regulatory
approval for increased density in the spacing of wells.

LEASE OPERATING EXPENSES: Expenses incurred in the operation of a producing
property as apportioned among the several parties in interest.

MCF: 1,000 cubic feet; the standard unit for measuring the volume of natural
gas.

MMBTU: One million British thermal units.

MULTIPLE COMPLETION WELL: A well which produces simultaneously through separate
tubing strings from two or more producing horizons or alternatively from each.

NET ACRES OR WELLS: The interests of BROG in such acres or wells.

NET OVERRIDING ROYALTY INTEREST: A share of gross production from a property,
measured by net profits from operation of the property and carved out of the
working interest, i.e., a net profits interest.

NET PROCEEDS: The excess of Gross Proceeds received by BROG during a particular
period over Production Costs for such period.

PAYADD: Completion in an existing well of additional productive zone(s) within a
producing formation.

PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES: The present value of the
Estimated Future Net Revenues computed using a discount rate of 10%.

PRODUCTION COSTS: Costs incurred on an accrual basis by BROG in operating the
Underlying Properties, including both capital and non-capital costs and
including, for example, development drilling, production and processing costs,
applicable taxes and operating charges.

PROVED DEVELOPED RESERVES: Those Proved Reserves which can be expected to be
recovered through existing wells with existing equipment and operating methods.

PROVED RESERVES: 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 UNDEVELOPED RESERVES: 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.

RECAVITATED WELL: A coal seam well, the production from which has been enhanced
or extended by the enlargement of the cavity within the coal deposit to which
the well has been completed.

RECOMPLETED WELL: A well completed by drilling a separate well-bore from an
existing casing in order to reach the same reservoir, or re-drilling the same
well bore to reach a new reservoir after production from the original reservoir
has been abandoned.

ROYALTY: The principal asset of the Trust; the 75% net overriding royalty
interest conveyed to the Trust on November 3, 1980, by Southland Royalty
Company, the predecessor to BROG, which was carved out of the Underlying
Interests.

ROYALTY INCOME: The monthly Net Proceeds attributable to the Royalty.

SECTION 29 TAX CREDIT: A federal income tax credit available under Section 29 of
the Internal Revenue Code for producing coal seam gas (and other nonconventional
fuels) from wells drilled prior to January 1, 1993, to a formation beneath a
qualifying coal seam formation, and for production from wells drilled after
December 31, 1979, but prior to January 1, 1993, which are later completed into
such a formation.

SPOT PRICE: The price paid for gas, oil or oil products sold under contracts for
the purchase and sale of such minerals on a short-term basis.

UNDERLYING INTERESTS: The working, royalty and other interests owned by
Southland Royalty Company, the predecessor to BROG, in properties located in the
San Juan Basin of northwest New Mexico, out of which the Royalty was carved.

UNDERLYING PROPERTIES: The real property located in the San Juan Basin of
northwestern New Mexico burdened by the Underlying Interests.

UNITS OF BENEFICIAL INTEREST: The units of ownership of the Trust, equal to the
number of shares of common stock of Southland Royalty Company outstanding at the
close of business on November 3, 1980.

WORKING INTEREST: The operating interest under an oil and gas lease.

                                       17
<PAGE>

                 SAN JUAN BASIN ROYALTY TRUST TEXASBANK, TRUSTEE
   2525 RIDGMAR BOULEVARD, SUITE 100 -- FORT WORTH, TEXAS 76116 866-809-4553
                                -- WWW.SJBRT.COM