##### 



EXHIBIT 13 SAN JUAN BASIN ROYALTY TRUST
2003 ANNUAL REPORT & FORM 10-K




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For generations, explorers, frontiersmen, miners and ranchers have been drawn
to New Mexico. The natural resources that attracted them to the area are the
same ones that provide opportunities for us today. And as we
examine the history they left behind in decaying ruins and abandoned mines,
were reminded that no matter how much things change, our fascination with the
land and its hidden treasures will always remain the same. LAKE VALLEY, NEW MEXICO (PIONEER STORE GRAPHIC) Like so many ghost towns, Lake Valley had its humble beginnings, prosperous
heydays and tragic ending. In 1882, John Leavitt discovered a huge cavern lined
with solid silver  later named The Bridal Chamber for its crystal-encrusted
walls. But as is often the case, with wealth comes trouble. Lake Valley became
known for its lawlessness. So to bring order, Jim Courtright, a.k.a. Longhair
Jim, was hired as town marshall in 1882. After that, things settled down  in
more ways than one. In 1893, silver was devalued, propelling the town into a
downward slide. Then in 1895, most of Main Street burned to the ground. Today,
Lake Valley is managed by the Bureau of Land Management, which has begun a
program to protect the area and stabilize some of the structures.




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THE TRUST The principal asset of the San Juan Basin Royalty Trust (the Trust) consists
of a 75% net overriding royalty interest (the Royalty) carved out of certain
oil and gas leasehold and royalty interests in properties located in the San
Juan Basin of northwestern New Mexico (the Underlying Properties). UNITS OF BENEFICIAL INTEREST The units of beneficial interest of the Trust (the Units) are traded on the
New York Stock Exchange under the symbol SJT. At March 8, 2004, the closing
price of a Unit was $19.93. From January 1, 2002, to December 31, 2003, the
quarterly high and low closing sales prices and the aggregate amount of monthly
distributions per Unit paid each quarter were as follows: DistributionsHigh
    
    Low
    
    Paid2003First Quarter
    
    $
    15.8700
    
    
    $
    13.6500
    
    
    $
    .418337Second Quarter
    
    
    19.7600
    
    
    
    14.3700
    
    
    
    .549655Third Quarter
    
    
    18.0800
    
    
    
    16.1300
    
    
    
    .511093Fourth Quarter
    
    
    21.8900
    
    
    
    18.0900
    
    
    
    .459559TOTAL FOR 2003
    
    
    
    
    
    
    
    
    
    $
    1.9386442002First Quarter
    
    $
    11.9000
    
    
    $
    9.2500
    
    
    $
    .075673Second Quarter
    
    
    12.2300
    
    
    
    10.4900
    
    
    
    .193414Third Quarter
    
    
    11.8800
    
    
    
    9.7000
    
    
    
    .263820Fourth Quarter
    
    
    13.9000
    
    
    
    11.7000
    
    
    
    .248447TOTAL FOR 2002
    
    
    
    
    
    
    
    
    
    $
    .781354
 At March 8, 2004, there were 46,608,796 Units outstanding held by 1,972 Unit holders of record. The
following table presents information relating to the distribution of record ownership of Units: NUMBER OFTYPE OF UNIT HOLDERS
    
    UNIT HOLDERS
    
    UNITS HELDIndividuals, Individual Retirement Accounts, Joint Holders and Minors
    
    
    1,731
    
    
    
    1,991,139Fiduciaries
    
    
    188
    
    
    
    482,177Clubs, Associations or Societies
    
    
    8
    
    
    
    89,335Banks
    
    
    8
    
    
    
    17,285Depositories
    
    
    1
    
    
    
    43,688,821Corporations
    
    
    35
    
    
    
    339,209Government Bodies
    
    
    1
    
    
    
    830TOTAL
    
    
    1,972
    
    
    
    46,608,796
 1




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TO UNIT HOLDERS We are pleased to present the 2003 Annual Report of the San Juan Basin Royalty
Trust. The
report includes a copy of the Trusts Annual Report on Form 10-K filed with the
Securities and
Exchange Commission (the Commission) for the year ended December 31, 2003,
without exhibits.
The Form 10-K contains important information concerning the Underlying
Properties, defined below,
including the oil and gas reserves attributable to the 75% net overriding
royalty interest owned by the Trust. 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 current owner of the
Underlying Properties, as defined below, and the successor, through a series of
assignments and mergers, to Southland Royalty Company (Southland Royalty). T The
Trust was established in November 1980 by 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) (the Royalty), carved out of Southland Royaltys oil
and gas leasehold and royalty interests in properties in the San Juan Basin of
northwestern New Mexico (the Underlying Properties). The Royalty is the
principal asset of the Trust.


T Under the Indenture governing the Trust,
TexasBank, 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.


T Income distributed to Unit holders in
2003 was $90,357,837 or $1.938644 per Unit. Distributable Income for 2003
consisted of Royalty Income of $91,997,262 plus interest income of $43,882,
less administrative expenses of $1,683,307.


T 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.


T Certain Royalty Income is generally considered portfolio income under the
passive loss rules of the
Internal Revenue Code. Therefore, Unit holders should generally 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. T 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, 2004, and for the year ending December 31, 2004. Unit holders
owning Units in nominee name may obtain monthly tax
information from the Trustee upon request. T For readers convenience, a glossary
of definitions used in
this report can be found on the inside back cover. Please visit our Web site at
www.sjbrt.com to access news releases, reports, Commission filings and tax
information. TexasBank, TrusteeBy:
    
    (-s- LE ANN ANDERSON)Lee Ann AndersonVice President and Trust Officer
 2




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SHAKESPEARE, NEW MEXICO (COVERED WAGON GRAPHIC) As home to such colorful characters as Bean Belly Smith, Russian Jack, Flora
Belle, Happy Bob Fambo and Curley Bill, Shakespeare was a mining town that
benefited mainly from its reliable water source.
This small spring attracted Indians, Spaniards and even a skinny blond kid with
buck teeth to town
who was looking for a job. He was too young and small for heavy work so he
found employment washing dishes
in the Stratford Hotel. After he left Shakespeare, he eventually made his way
to Lincoln County, where he became known as Billy the Kid. After frequent
name changes, a fraudulent diamond strike to lure rich East-coast investors,
and a gunfight over a breakfast egg, Shakespeare will always be known as one of
the most interesting towns in New Mexico. And while many buildings remain
today, several were severely damaged by a recent fire.




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DESCRIPTION OF THE PROPERTIES The principal asset of the Trust is a 75% net overriding royalty interest (the
Royalty) carved out of certain working, royalty and other interests owned by
BROG in oil and gas 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 consist of
working interests, royalty interests, overriding royalty interests and other
contractual rights in 151,900 gross (119,000 net) producing acres and 3,946
gross (1,170 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 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, 2003, the production index for the Underlying Properties is estimated to be
approximately 9.65 years. The production index is subject to change from year
to year based on reserve revisions and production levels and is not presented
as an estimate of the life expectancy of the Trust. Independent petroleum
engineers retained by the Trust have estimated the Underlying Properties could
remain productive well beyond the stated production index. Among the factors
considered by 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 July 2003, the OCD approved 160-acre
spacing in the Fruitland Coal formation. Eighty-acre spacing has been permitted
in the Mesaverde formation since 1997. 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. The price of coal seam gas is typically lower than the price of
conventional gas. This is because the heating value of coal seam gas is much
lower than that of conventional gas due to (a) ever-increasing percentages of
carbon dioxide in coal seam gas (carbon dioxide has no heating value) and (b)
the presence of heavier hydrocarbons such as ethanes, propanes and butanes in
conventional gas. Furthermore, the processing
fees for coal seam gas are typically higher than the processing fees for
conventional gas due to the cost of extracting the carbon dioxide. The coal
seam production from the Underlying Properties for the December 2003 production
month was approximately 40.6% of the total gas production for that month. Sales of production from coal seam wells drilled prior to January 1, 1993,
qualified for federal income tax credits through 2002. Although both houses of
Congress are presently considering energy legislation, including provisions to
extend or reinstate the Section 29 credit in various ways, whether such
provisions will be enacted into law, and if so, the effect thereof on the Trust
and the Unit holders is, at present, unknown. For 2002, the credit was
approximately $1.09 per MMBtu. Even though the Section 29 credit does not apply
to qualified fuel sold in 2003, a Section 29 credit in the amount of $.02 per
Unit may apply to proceeds received in 2003 for qualified fuel sold in 2002 and
earlier years for cash basis Unit holders that held Units during January and
February 2003. The Internal Revenue Service has issued a private letter ruling
to another taxpayer to the effect that cash method taxpayers may claim the
Section 29 credit in a later year for sales of qualified fuel in an earlier
year where the proceeds from such sales are received in the later year. Because
a private letter ruling may be relied on only by the taxpayer who requested the
ruling, the Trust applied for a similar ruling. Tax counsel to the Trust has
been informed that the Internal Revenue Service intends to issue a Revenue
Procedure in the near future allowing a cash basis taxpayer to report the
Section 29 credit in either the year the qualifying production is sold or the
year the income is received, provided that the taxpayer is consistent in its
treatment from year to year and that, accordingly, it will not issue private
letter rulings on this question. No assurance can be given, however, whether,
or when, such a Revenue Procedure will be issued. 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. T 4




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TRUSTEES DISCUSSION & ANALYSIS GAS AND OIL PRODUCTION Total gas and oil production from the Underlying Properties for the five years
ended December 31, 2003, were as follows: 2003
    
    2002
    
    2001
    
    2000
    
    1999Gas  Mcf
    
    
    45,202,576
    
    
    
    46,206,297
    
    
    
    42,960,149
    
    
    
    42,220,260
    
    
    
    39,940,175Mcf per Day
    
    
    123,843
    
    
    
    126,593
    
    
    
    117,699
    
    
    
    115,356
    
    
    
    109,425Oil  Bbls
    
    
    74,727
    
    
    
    93,659
    
    
    
    92,413
    
    
    
    97,330
    
    
    
    72,223Bbls per Day
    
    
    205
    
    
    
    257
    
    
    
    253
    
    
    
    266
    
    
    
    198
 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: 2003
    
    2002
    
    2001
    
    2000
    
    1999Gas  Mcf
    
    
    25,922,650
    
    
    
    19,584,056
    
    
    
    19,272,021
    
    
    
    20,317,750
    
    
    
    19,527,666Average Price (per Mcf)
    
    $
    3.93
    
    
    $
    2.32
    
    
    $
    4.61
    
    
    $
    2.99
    
    
    $
    1.78Oil  Bbls
    
    
    43,123
    
    
    
    40,215
    
    
    
    42,056
    
    
    
    47,411
    
    
    
    35,341Average Price (per Bbl)
    
    $
    26.11
    
    
    $
    20.90
    
    
    $
    24.99
    
    
    $
    24.66
    
    
    $
    14.41
 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. 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 and existing 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. BROG has entered into two contracts for the sale of all volumes of gas produced
from the Underlying Properties. These contracts provide for (i) the sale of
such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services,
respectively, (ii) the delivery of such gas at various delivery points through
March 31, 2005, and from year to year thereafter until terminated by either
party on 12 months notice, and (iii) for the sale of such gas at prices which
fluctuate in accordance with published indices for gas sold in the San Juan
Basin of northwestern
New Mexico. Effective January 1, 2004, the rights and obligations of Duke
Energy and Marketing L.L.C. were assumed by ConocoPhillips Company pursuant to
an Assignment and Novation Agreement. Prior to April 1, 2002, the gas produced
from the Underlying Properties was sold to Duke Energy and Marketing L.L.C. 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 and gas receipt points. Such
disclosure could compromise the ability to compete effectively in the
marketplace for the sale of gas produced from the Underlying Properties. 5




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TRUSTEES DISCUSSION & ANALYSIS ROYALTY INCOME Royalty Income consists of monthly Net Proceeds attributable to the Royalty.
Royalty Income for the five years ended December 31, 2003, was determined as
shown in the following table: 2003
    
    2002
    
    2001
    
    2000
    
    1999GROSS PROCEEDS
FROM THE UNDERLYING
PROPERTIES:Gas
    
    $
    175,653,183
    
    
    $
    103,349,299
    
    
    $
    169,052,231
    
    
    $
    124,902,689
    
    
    $
    69,928,312Oil
    
    
    1,938,972
    
    
    
    1,863,827
    
    
    
    2,233,071
    
    
    
    2,409,158
    
    
    
    1,028,862Other
    
    
    (1,202,368
    )(1)
    
    
    (5,110,589
    )(2)
    
    
    0
    
    
    
    4,653,333
    (3)
    
    
    1,189,996
    (4)TOTAL
    
    $
    176,389,787
    
    
    $
    100,102,537
    
    
    $
    171,285,302
    
    
    $
    131,965,180
    
    
    $
    72,147,170LESS PRODUCTION COSTS:Capital Expenditures
    
    
    20,590,704
    
    
    
    21,470,777
    
    
    
    32,999,973
    
    
    
    25,575,657
    
    
    
    10,556,159
    (5)Severance Tax  Gas
    
    
    17,281,986
    
    
    
    9,752,508
    
    
    
    16,687,074
    
    
    
    12,059,286
    
    
    
    7,180,973Severance Tax  Oil
    
    
    174,750
    
    
    
    151,594
    
    
    
    202,113
    
    
    
    234,462
    
    
    
    106,335Other
    
    
    41,850
    
    
    
    18,037
    
    
    
    55,000
    
    
    
    129,161
    
    
    
    (95,445
    )Lease Operating Expenses
and Property Taxes
    
    
    15,637,481
    
    
    
    15,701,740
    
    
    
    15,109,139
    
    
    
    13,906,916
    (5)
    
    
    10,896,526TOTAL
    
    
    53,726,771
    
    
    
    47,094,656
    
    
    
    65,053,299
    
    
    
    51,905,482
    
    
    
    28,644,548Excess Production Costs
    
    
    0
    
    
    
    (2,259,628
    )(6)
    
    
    2,259,628
    (6)
    
    
    0
    
    
    
    0Interest on Excess
Production Costs
    
    
    0
    
    
    
    (10,545
    )(6)
    
    
    0
    
    
    
    0
    
    
    
    0Net Profits
    
    
    122,663,016
    
    
    
    50,737,708
    
    
    
    108,491,631
    
    
    
    80,059,698
    
    
    
    43,502,622Net Overriding
Royalty Interest
    
    
    75
    %
    
    
    75
    %
    
    
    75
    %
    
    
    75
    %
    
    
    75
    %Royalty Income
    
    $
    91,997,262
    
    
    $
    38,053,281
    
    
    $
    81,368,723
    
    
    $
    60,044,773
    
    
    $
    32,626,966
 (1) Represents a settlement between BROG and the Mineral Management Service of
the United States Department of the Interior (the MMS). (2) Represents deductions by BROG from the net proceeds otherwise payable to
the Trust in connection with the portion of various settlement agreements with
the MMS allocable to the Royalty (see Item 3 of Trusts Annual Report on Form
10-K). (3) Included in 2000 Distributable Income, as defined below, 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. (4) Included in 1999 Distributable Income was a payment by BROG to the Trust
in March 1999 of $892,498. After a pipeline rupture 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. (5) 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 Royalty 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. (6) See Note 8 to the Financial Statements included herein. DISTRIBUTABLE INCOME 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, 2003, Distributable Income was $90,357,837,
representing a 148% increase from 2002. For the year ended December 31, 2002,
Distributable Income was $36,417,967, representing a 55% decrease from 2001.
Distributable Income in 2001 was $80,126,202. The Trust received Royalty Income of $91,997,262 and interest income of $43,882
in 2003. After deducting
administrative expenses of $1,683,307, Distributable Income for 2003 was
$90,357,837 ($1.938644 per Unit). In 2002, Royalty Income was $38,053,281,
interest income was $16,112, administrative expenses were $1,728,187, and cash
reserves decreased $76,761, resulting in Distributable Income of $36,417,967
($0.781354 per Unit). The 148% increase in Distributable Income from 2002 to
2003 was primarily attributable to higher gas and oil prices which resulted in
increased Royalty Income. Distributable Income for 2003 exceeds 2001 primarily
due to decreased capital expenditures in 2003 as compared to 2001. In addition,
interest earnings in 2003 were higher, as compared to 2002, primarily due to an
increase in funds available for investment. Administrative expenses were
slightly lower in 6




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TRUSTEES DISCUSSION & ANALYSIS 2003, as compared to 2002, primarily as a result of differences in timing in
the receipt and payment of these expenses. In 2001, the Trust received Royalty Income of $81,368,723 and interest income
of $165,676. After deducting administrative expenses of $1,216,577,
Distributable Income for 2001 was $80,126,202 ($1.719123 per Unit). The 55%
decrease in Distributable Income from 2001 to 2002 was primarily attributable
to lower gas and oil prices as well as the loss of the Val Verde Credit. In
addition, interest earnings in 2002 were lower, as compared to 2001, primarily
due to a decrease in funds available for investment and lower interest rates in
2002. Administrative expenses were higher primarily because administrative
expenses in 2002 included expenses incurred in addressing certain marketing and
joint interest audit disputes between the Trust and BROG, as well as expenses
incurred in conducting a special meeting of Unit holders to appoint a successor
Trustee of the Trust and to approve amendments to the Indenture governing the
Trust. See Note 12 to the Financial Statements included herein. OPERATING EXPENSES Monthly operating expenses of the Underlying Properties, exclusive of property
taxes, in 2003 averaged approximately $1,250,600, which is lower than the
$1,262,900 average in 2002 and higher than the $1,242,200 average in 2001.
Operating expenses for 1999 through 2001 include the impact of the annual
inclusion of $250,000 from BROG as an offset to lease operating expenses 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. SETTLEMENTS As part of the September 4, 1996, settlement of the litigation filed by the
Trustee on June 4, 1992, against BROG and Southland Royalty, 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. Effective July 1, 2002, BROG sold the Val
Verde facility. Accordingly, effective July 1, 2002, the calculation of net
proceeds for gas gathered and treated at the Val Verde facility no longer
includes the Val Verde Credit. The total amount of the Val Verde Credit for the
12 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 resulted
in increased costs allocated to the Trust for coal seam gas gathered and
treated on the Val Verde system and accordingly, decreased the Royalty Income
received by the Trust. As a part of that same litigation settlement, the Trustee and BROG established
a formal protocol pursuant to which joint interest auditors retained by the
Trustee gained improved access to BROGs books and records as applicable to the
Underlying Properties. The audit process was initiated in 1996 and, since
inception, has resulted in audit exceptions being granted by and payments
received from BROG totaling approximately $10,750,000. CAPITAL EXPENDITURES In February 2003, BROG announced an estimated capital budget for the Underlying
Properties of $14.1 million. During the year, the estimate was initially
increased to $18.0 million, and ultimately increased to approximately $21.1
million. BROGs capital plan for the Underlying Properties for 2003 estimated
351 projects, including the drilling of 38 new wells to be operated by BROG and
26 new wells to be operated by third parties. In 2003, BROG actually
participated in 509 projects, including the drilling of 58 new wells operated
by BROG as well as 10 other 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 Royalty
Income for 2003 include approximately $6.5 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 Royalty 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. In addition, with respect to 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 $14.6 million for 2003 budgeted
projects were used in calculating Royalty Income in calendar year 2003, and
approximately $5.3 million in capital expenditures was used in calculating
Royalty Income for January and February 2004. 7




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TRUSTEES DISCUSSION & ANALYSIS Therefore, an additional approximately $1.2 million in capital expenditures for
2003 projects remains to be spent. During 2003, in calculating Royalty Income, BROG deducted approximately $20.6
million of capital expenditures for projects, including drilling and completion
of 44 gross (15.36 net) conventional wells, recompletion of two gross (.07 net)
conventional wells, three gross (.94 net) miscellaneous capital projects, 29
gross (21.55 net) restimulations, 49 gross (3.22 net) conventional payadds, 53
gross (16.98 net) coal seam wells, nine gross (1.6 net) coal seam
recompletions, two gross (.92 net) coal seam recavitations, one gross (.04 net)
coal seam restimulation, two gross (.88 net) miscellaneous coal seam capital
projects and facilities maintenance. There were 32 gross (7.0 net) new conventional wells, recompletion of 15 gross
(3.72 net) conventional wells, 22 gross (9.11 net) conventional well
restimulations, 14 gross (3.56 net) conventional payadds, 54 gross (14.43 net)
coal seam wells, six gross (1.62 net) coal seam recompletions, one gross (.002
net) recavitation and six gross (.20 net) miscellaneous coal seam capital
projects in progress as of December 31, 2003. During 2002, in calculating Royalty Income, 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,
one gross (.82 net) restimulation, one 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, five gross (.98 net)
coal seam recavitations and three 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, four gross (1.41 net) coal seam
wells, two gross (.99 net) coal
seam recompletions and five gross (1.72 net) miscellaneous coal seam capital
projects in progress as of December 31, 2002. During 2001, in calculating Royalty Income, 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,
three gross (2.34 net) restimulations, 56 gross (8.40 net) conventional
payadds, 10 gross (1.52 net) coal seam wells, four gross (1.61 net) coal seam
recompletions, one gross (.88 net) coal seam payadd, six 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,
two gross (.87 net) miscellaneous conventional capital projects, nine gross
(3.17 net) conventional payadds, 15 gross (1.09 net) conventional
restimulations, 12 gross (5.36 net) coal seam wells, seven gross (4.11 net)
coal seam recompletions, two gross (.02 net) coal seam restimulations and six
gross (.29 net) miscellaneous coal seam capital projects in progress as of
December 31, 2001. For 2004, BROGs announced plan for the Underlying Properties includes 441
projects at an aggregate cost of
$18.5 million. Approximately $11.7 million of that budget is allocable to new
wells, with approximately 61% 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 2004
could range from $15 million to $25 million. BROG has indicated that,
principally as a result of the OCDs approval of reduced, 160-acre spacing in
the Fruitland Coal formation, BROGs budget for 2004 reflects a continued focus
on that formation. BROG indicates its budget for 2004 reflects continued significant development
of conventional formations, including infill drilling to the Mesaverde and
Dakota formations, development of the Fruitland Coal formation and multiple
formation completions. A majority of the new wells for 2004 are projected to be
drilled on Underlying Properties in which the fractional working interest
included in the Underlying Properties is relatively low, but many of the
recompletions and restimulations are scheduled on properties in which such
working interest is relatively high. CONTRACTUAL OBLIGATIONS Under the Indenture governing the Trust, 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. As of January 1, 2003,
the administrative fee due under items (i) and (ii) above will not 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). 8




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##### 



TRUSTEES DISCUSSION & ANALYSIS 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 Securities 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 Commission and NYSE
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 and the
NYSE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. During the year, the Commission adopted rules implementing legislation
concerning governance matters for publicly-held entities that was passed as
part of the Sarbanes-Oxley Act of 2002. In addition, the NYSE adopted
additional corporate governance rules. Not all of the governance requirements
are applicable to passive entities such as the Trust. 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: T Royalty Income recorded for a month is the amount computed and paid by BROG
to the Trustee for the Trust. T Trust expenses recorded are based on liabilities paid and cash reserves
established from Royalty Income for liabilities and contingencies. T Distributions to Unit holders are recorded when declared by the Trustee. T The conveyance which transferred the Royalty to the Trust provides that any
excess of production costs applicable to the Underlying Properties over gross
proceeds from such properties must be recovered from future net profits before
Royalty Income is again paid to the Trust. 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. (MAP) 9




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##### 



TRUSTEES DISCUSSION & ANALYSIS RESULTS OF THE 4TH QUARTERS OF 2003 & 2002 For the three months ended December 31, 2003, Distributable Income was
$21,419,523 ($.459559 per Unit), which was more than the $11,579,818 ($.248447
per Unit) of income distributed during the same period in 2002. The increase in
Distributable Income resulted primarily from higher average gas and oil prices. 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, 2003 and 2002 were as follows: 2003
    
    2002UNDERLYING PROPERTIESGas  Mcf
    
    
    11,677,586
    
    
    
    11,608,135Mcf per Day
    
    
    126,930
    
    
    
    126,175Average Price (per Mcf)
    
    $
    3.71
    
    
    $
    2.30Oil  Bbls
    
    
    17,216
    
    
    
    19,624Bbls per Day
    
    
    187
    
    
    
    213Average Price (per Bbl)
    
    $
    25.77
    
    
    $
    23.61ATTRIBUTABLE TO THE ROYALTYGas  Mcf
    
    
    6,453,617
    
    
    
    5,574,600Oil  Bbls
    
    
    9,532
    
    
    
    9,184
 The average price of gas and oil increased in 2003 compared to the prior year.
The price per barrel of oil during the fourth quarter of 2003 was $2.16 per Bbl
higher than that received in the fourth quarter of 2002 due to increases in oil
prices in world markets generally, including the posted price applicable to the
Royalty. Gas production increased slightly primarily due to increased demand. Capital costs for the fourth quarter of 2003 totaled $6,861,521 compared to
$4,653,069 during the same
period of 2002. The increase was primarily due to increased drilling activity
in the fourth quarter of 2003. Lease operating expenses and property taxes for
the fourth quarter of 2003 averaged $1,163,120 per month compared to $1,322,655
per month in the fourth quarters of 2002. Based on 46,608,796 Units outstanding, the per-Unit distributions during the
fourth quarter of 2003 and 2002 were as follows: 2003
    
    2002October
    
    $
    .143777
    
    
    $
    .115816November
    
    
    .166295
    
    
    
    .043379December
    
    
    .149487
    
    
    
    .089252QUARTER TOTAL
    
    $
    .459559
    
    
    $
    .248447
 10




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##### 



CHLORIDE, NEW MEXICO (ADOBE HOMESTEAD) With a history of bullfights and bare-handed battles with bears, this one-time
tent camp grew to a full-fledged town within six months of its first silver
strike. An active imagination can take one back to what Chloride was like in
the 1880s when eight saloons, three general stores, two barber shops, a Chinese
laundry and a hotel were part of the thriving economy. But the town lacked one
thing: women. In an attempt to overcome this scarcity, a free building site was
offered to the first lady who moved to Chloride. It must have worked, because
in 1882 the local newspaper reported that the city had at least one brothel,
and probably more. Today, Chloride is truly a ghost town. The pioneer store is
a museum and the old hanging tree still grows in the middle of Main Street.




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##### 



SAN JUAN BASIN ROYALTY TRUST STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS December 31, 2003 and 2002 ASSETS
    
    2003
    
    2002Cash and Short-Term Investments
    
    $
    7,082,284
    
    
    $
    4,274,790Net Overriding Royalty Interests in Producing Oil and Gas Properties  Net
    
    
    29,822,820
    
    
    
    33,697,906TOTAL
    
    $
    36,905,104
    
    
    $
    37,972,696LIABILITIES AND TRUST CORPUSDistribution Payable to Unit Holders
    
    $
    6,967,426
    
    
    $
    4,159,932Cash Reserves
    
    
    114,858
    
    
    
    114,858Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding
    
    
    29,822,820
    
    
    
    33,697,906TOTAL
    
    $
    36,905,104
    
    
    $
    37,972,696
 STATEMENTS OF DISTRIBUTABLE INCOME For the Three Years Ended December 31, 2003 2003
    
    2002
    
    2001Royalty Income
    
    $
    91,997,262
    
    
    $
    38,053,281
    
    
    $
    81,368,723Interest Income
    
    
    43,882
    
    
    
    16,112
    
    
    
    165,67692,041,144
    
    
    
    38,069,393
    
    
    
    81,534,399Expenditures  General and Administrative
    
    
    1,683,307
    
    
    
    1,728,187
    
    
    
    1,216,577Change in Cash Reserves
    
    
    
    
    
    
    (76,761
    )
    
    
    191,620Distributable Income
    
    $
    90,357,837
    
    
    $
    36,417,967
    
    
    $
    80,126,202Distributable Income Per Unit (46,608,796 units)
    
    $
    1.938644
    
    
    $
    0.781354
    
    
    $
    1.719123
 STATEMENTS OF CHANGES IN TRUST CORPUS For the Three Years Ended December 31, 2003 2003
    
    2002
    
    2001Trust Corpus, Beginning of Period
    
    $
    33,697,906
    
    
    $
    37,859,749
    
    
    $
    40,686,854Amortization of Net Overriding Royalty Interest
    
    
    (3,875,086
    )
    
    
    (4,161,843
    )
    
    
    (2,827,105
    )Distributable Income
    
    
    90,357,837
    
    
    
    36,417,967
    
    
    
    80,126,202Distribution Declared
    
    
    (90,357,837
    )
    
    
    (36,417,967
    )
    
    
    (80,126,202
    )Trust Corpus, End of Period
    
    $
    29,822,820
    
    
    $
    33,697,906
    
    
    $
    37,859,749
 The accompanying Notes to Financial Statements are an integral part of these statements. 12




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##### 



NOTES TO FINANCIAL STATEMENTS SAN JUAN BASIN ROYALTY TRUST 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 Royalty)
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 Royaltys shareholders
of record as of November 3, 1980, who received one Unit in the Trust for each
share of Southland Royaltys common stock held. The Units are traded on the New
York Stock Exchange. The terms of the Trust Indenture provide, among other things, that: T 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; T 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; T The Trustee may establish a cash reserve for the payment of any liability
which is contingent or uncertain in amount; T The Trustee is authorized to borrow funds to pay liabilities of the Trust;
and T 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 by the Trustee. 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 10 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 proceeds received by the owner
of the Underlying Properties 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, 2003 and 2002 aggregated
$103,452,708 and $99,577,622 respectively. 3. BASIS OF ACCOUNTING The Financial Statements of the Trust are prepared on the following basis: T Royalty Income recorded for a month is the amount computed and paid by the
owner of the Underlying Properties, Burlington Resources Oil & Gas Company LP
(BROG), to the Trustee for the Trust. Royalty Income consists of the amounts
received by the owner of the Underlying Properties from the sale of production
less applicable accrued production costs, development and drilling costs,
applicable taxes, operating charges, and
other costs and deductions, multiplied by 75%. T Trust expenses recorded are based on liabilities paid and cash reserves
established from Royalty Income for liabilities and contingencies. T Distributions to Unit holders are recorded when declared by the Trustee. T The conveyance which transferred the Royalty to the Trust provides that any
excess of production costs applicable to the Underlying Properties over net
proceeds from such properties must be recovered from future net profits before
Royalty Income is again paid to the Trust. The Financial Statements of the
Trust differ from Financial Statements prepared in accordance with United
States 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. 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. 13




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##### 



T NOTES TO FINANCIAL STATEMENTS T 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 such tax treatment. Sales of production from coal seam wells drilled prior to January 1, 1993,
qualified for federal income tax credits through 2002. Although both houses of
Congress are presently considering energy legislation, including provisions to
extend or reinstate the Section 29 credit in various ways, whether such
provisions will be enacted into law, and if so, the effect thereof on the Trust
and the Unit holders is at present, unknown. Even though the Section 29 credit
does not apply to qualified fuel sold in 2003, a Section 29 credit (at the rate
applicable in 2002) may apply to proceeds received in 2003 for qualified fuel
sold in 2002 and earlier years for Unit holders that utilize the cash method of
tax accounting. The Internal Revenue Service has issued a private letter
ruling to another taxpayer to the effect that cash method taxpayers may claim
the Section 29 credit in a later year for sales of qualified fuel in an earlier
year where the proceeds from such sales are received in the later year. Because
a private letter ruling may be relied on only by the taxpayer who requested the
ruling, the Trust applied for a similar ruling. Tax counsel to the Trust has
been informed that the Internal Revenue Service intends to issue a Revenue
Procedure in the near future allowing a cash basis taxpayer to report the
Section 29 credit in either the year the qualifying production is sold or the
year the income is received, provided that the taxpayer is consistent in its
treatment from year to year and that, accordingly, it will not issue private
letter rulings on this question. No assurance can be given, however, whether,
or if so when, such a Revenue Procedure will be issued. To benefit from the credit in 2003, each cash basis Unit Holder must determine
from the tax information the Unit Holder received from the Trust, its pro rata
share of qualifying production of the Trust sold before January 1, 2003, based
upon the number of Units owned during each month of the year, and the amount of
available credit per MMbtu for the year, and then apply the tax credit against
the Unit Holders own income tax liability, but such credit could not reduce
the Unit Holders regular tax liability (after the foreign tax credit and
certain other nonrefundable credits) below its 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 a taxpayers 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 circumstance. BROG has historically provided to the Trust summary Section 29 tax credit
information related to Trust properties. 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.
Substantially all of the wells burdened by the Royalty have received the
appropriate well category certification. BROG has informed the Trustee that it
will continue to seek certification of any qualified but not certified wells
burdened by the Royalty. Unless the Section 29 credit is extended or reinstated
in such a way as to include previously drilled wells, however, these actions
will not affect the Trust or its Unit holders in periods after December 31,
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 such as that derived through the Trust 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
pursuant to which joint interest auditors retained by the Trustee gained
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 from the Underlying Properties going
forward as follows: a. 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. b. 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 14




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##### 



T NOTES TO FINANCIAL STATEMENTS T make a deduction for marketing fees associated with sales of oil or natural gas
liquids products. c. The Trust retained access to BROGS current gas transportation, gathering,
processing and treating agreements with third parties through the remainder of
their primary terms. 6. CERTAIN CONTRACTS BROG has entered into two contracts for the sale of all gas from the
Underlying Properties. 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 such gas at various delivery points through
March 31, 2005, and from year to year thereafter until terminated by either
party on 12 months notice, and (iii) the sale of such gas at prices which
fluctuate in accordance with published indices for gas sold in the San Juan
Basin of northwestern New Mexico. Effective January 1, 2004, the rights and
obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips
Company pursuant to an Assignment and Novation Agreement. 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. 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. 8. 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 the Underlying Properties, the net profits applicable to
the Trust were reduced by approximately $3,624,117. This amount was deducted
in calculating Royalty Income 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. 9. 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. 10. MMS SETTLEMENT As part of a settlement between BROG and the Mineral Management Service of the
United States Department of the Interior, $901,776 was deducted from the
Trusts April 2003 royalty payment. This represents the Trusts 75% interest
of the total settlement. 11. 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. 12. AMENDMENTS TO THE TRUSTS INDENTURE 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. 13. 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, 2003 (in thousands, except unit
amounts): DISTRIBUTABLEINCOME ANDROYALTY
    
    DISTRIBUTABLE
    
    DISTRIBUTIONINCOME
    
    INCOME
    
    PER UNIT2003First Quarter
    
    $
    19,911
    
    
    $
    19,498
    
    
    $
    .418337Second Quarter
    
    
    26,051
    
    
    
    25,619
    
    
    
    .549655Third Quarter
    
    
    24,332
    
    
    
    23,821
    
    
    
    .511093Fourth Quarter
    
    
    21,703
    
    
    
    21,420
    
    
    
    .459559TOTAL
    
    $
    91,997
    
    
    $
    90,358
    
    
    $
    1.9386442002First Quarter
    
    $
    3,925
    
    
    $
    3,527
    
    
    $
    .075673Second Quarter
    
    
    9,560
    
    
    
    9,015
    
    
    
    .193414Third Quarter
    
    
    12,549
    
    
    
    12,296
    
    
    
    .263820Fourth Quarter
    
    
    12,019
    
    
    
    11,580
    
    
    
    .248447TOTAL
    
    $
    38,053
    
    
    $
    36,418
    
    
    $
    .781354
 15




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INDEPENDENT AUDITORS REPORT T TEXASBANK, AS TRUSTEE FOR THE SAN JUAN BASIN ROYALTY TRUST: T We have audited the accompanying statements of assets, liabilities and trust
corpus of the San Juan Basin Royalty Trust as of December 31, 2003 and 2002,
and the related statements of distributable income and changes in trust corpus
for each of the three years in the period ended December 31, 2003. 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 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 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, 2003 and 2002, and the distributable income
and changes in trust corpus for each of the three years in the period ended
December 31, 2003, on the basis of accounting described in Note 3 to the
financial statements. T (-s- WEAVER AND TIDWELL, L.L.P.)
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
March 5, 2004 SAN JUAN BASIN ROYALTY TRUST
    
    AUDITORS
    
    TRANSFER AGENTTexasBank, Trustee
    
    Weaver and Tidwell, L.L.P.
    
    Computershare Investor Services2525 Ridgmar Boulevard, Suite 100
    
    Fort Worth, Texas
    
    Transfer ServicesFort Worth, Texas 76116
    
    
    
    P.O. Box A3480Toll-free telephone: 866-809-4553
    
    LEGAL COUNSEL
    
    Chicago, Illinois 60609-3480www.sjbrt.com
    
    Vinson & Elkins L.L.P.sjt@texasbank.com
    
    Dallas, Texas
    
    For questions about distributionchecks, address changes and transferTAX COUNSEL
    
    procedures, call 312-360-5154Winstead, Sechrest & Minick, PCHouston, Texas
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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 degreesF. 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 Properties) 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
Properties. 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 sold
before 2003 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 PROPERTIES: The working, royalty and other interests owned by
Southland Royalty Company, the predecessor to BROG, in properties located in
the San Juan Basin of northwestern New Mexico, out of which the Royalty was
carved. 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. Photos (C) Copyright by Daniel Ter-Nedden /www.ghosttowngallery.com




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