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|2 0 0 4 A N N UA L R E P O RT  F O R M 1 0K
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|THE
ARSON BLAIR u Equipped with a cowboy hat, beard and boots, Carson Blair embodies the
true New Mexico cowboy. From the beautiful landscapes of Santa Fe, Carson designs jewelry that
attracts such big name collectors as Clint Eastwood, Willie Nelson and Melanie Griffith. With
his own silver and turquoise medicine bag around his neck, Carson and his jewelry shine on
the silver screen in movies like Serving Sara, On Any Given Sunday and Michael. From
silversmith to actor, Carson Blair embodies the independent spirit of New Mexico with his
multi-talents and rustic charm.
TO LEARN MORE ABOUT CARSONS WORK CALL HIM AT 817.602.7948.
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|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 (the Underlying Properties) in
properties located in the San Juan Basin of northwestern New Mexico.
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 10, 2005, the closing price of a Unit was $33.50. From January 1, 2003, to December 31, 2004, the quarterly high
and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows:
DISTRIBUTIONS
HIGH LOW PAID
2004
First Quarter $ 22.9700 $ 17.7600 $ .443948
Second Quarter 25.3700 19.6500 .536204
Third Quarter 30.8100 23.8700 .738093
Fourth Quarter 33.6900 27.0000 .628753
TOTAL for 2004 $ 2.346998
2003
First Quarter $ 15.9500 $ 13.3000 $ .418337
Second Quarter 20.0200 14.2900 .549655
Third Quarter 18.3300 15.6000 .511093
Fourth Quarter 22.0000 18.0100 .459559
TOTAL for 2003 $ 1.938644
At March 4, 2005, there were 46,608,796 Units outstanding held by 1,897 Unit holders of record.
The following table presents information relating to the distribution of record ownership of Units:
NUMBER OF
TYPE OF UNIT HOLDERS UNIT HOLDERS UNITS HELD
Individuals, Individual Retirement Accounts, Joint Holders and Minors 1,614 1,732,511
Fiduciaries 237 566,455
Clubs, Associations or Societies 7 13,217
Depositary (for all beneficial holders) 1 43,946,154
Corporations 38 350,459
TOTAL 1,897 46,608,796
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|Marking an anniversary is special. And since its our silver
anniversary, we thought it appropriate to showcase the San
Juan Basins other natural resources  its people and their
craft. Thats why we invited artists from the area to display
silver and turquoise pieces worthy of our 25th anniversary.
uWe are pleased to present the 2004 Annual Report of the San Juan Basin Royalty Trust. The report includes a copy of the Trusts
Annual Report on Form 10-K filed with the Securities and Exchange Commission (the Commission) for the year ended
December 31, 2004, without exhibits. The Form 10-K contains important information concerning the Underlying Properties,
as 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 Trustees Discussion and Analysis are based on information
provided by Burlington Resources Oil  Gas Company LP (BROG), the current owner of the Underlying Properties and the
successor, through a series of assignments and mergers, to Southland Royalty Company (Southland Royalty). u 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 Royaltys oil and gas leasehold and royalty interests (the Underlying Properties) in properties in the
San Juan Basin of northwestern New Mexico. The Royalty is the principal asset of the Trust. u Under the Indenture governing
the Trust, TexasBank, as Trustee, has the primary function of collecting monthly net proceeds attributable to the Royalty
(Royalty Income) 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 in 2004 was $109,390,735 or $2.346998 per Unit.
Distributable Income for 2004 consisted of Royalty Income of $111,042,767 plus interest income of $58,885, less administrative
expenses of $1,710,917. u Information about the Trusts 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. u
Independent petroleum engineers retained by the Trust have estimated the Underlying Properties could remain productive well
beyond the stated production index of approximately 10.15 years and BROG has published information identifying the San Juan
Basin as the largest single gas field in the United States and observing that it will remain a major gas resource for decades to come.
In support of this observation, BROG cites the November 2002 U.S. Geological Survey study doubling its estimates of the gas
reserves in the San Juan Basin to over 50 trillion cubic feet. u 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. u 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, 2005, and for the year ending December 31, 2005. Unit
holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request. u For the readers
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, Trustee
By:
LEE ANN ANDERSON
Vice President and Trust Officer
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|UANE MAKTIMA u Twenty-nine years of experience has given this Native American designer
a fine eye for detail. Duane Maktima mixes functionality with form to produce a wide range of
designs that have won him more than a handful of accolades. Duanes cultural influences stem
from his Laguna and Hopi Indian heritage. He works and lives in Glorieta, New Mexico and his
artistry reflects the colors, motifs and natural forms of his esteemed Indian heritage. A southwestern
flair gives Duanes designs just the right creative touch. And all his work is produced with the
intent to preserve and pass on his Native American culture to the next generation.
WWW.DUANEMAKTIMA.COM
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|The principal asset of the Trust is a 75% net
overriding royalty interest (the Royalty)
carved out of certain working, royalty and
other leasehold interests (the Underlying
Properties) 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 consist of working interests, royalty interests,
overriding royalty interests and other contractual rights in
151,900 gross (119,000 net) producing acres and 4,223 gross
(1,240 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
Trusts independent petroleum engineers as of December 31,
2004, the production index for the Underlying Properties is
estimated to be approximately 10.15 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. 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 addition to gas from conventional wells, the Underlying
Properties also produce gas from coal seam wells completed to
the Fruitland Coal formation. 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 $550,000. 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 absence of heavier hydrocarbons
such as ethanes, propanes, and butanes which are present 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 2004 production month was
approximately 44% of the total gas production for that month.
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 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.
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|u DE S CRIP TION yTHE PROPERTIE Su uTRUSTEES DISCUSSION b ANALYSIS u
GA S AND OI L PRODUC T I O N
Total gas and oil production from the Underlying Properties for the five years ended December 31, 2004, were as follows:
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:
2004 2003 2002 2001 2000
Gas  Mcf 44,015,816 45,202,576 46,206,297 42,960,149 42,220,260
Mcf per Day 120,262 123,843 126,593 117,699 115,356
Oil  Bbls 77,341 74,727 93,659 92,413 97,330
Bbls per Day 211 205 257 253 266
2004 2003 2002 2001 2000
Gas  Mcf 25,324,435 25,922,650 19,584,056 19,272,021 20,317,750
Average Price (per Mcf) $4.68 $3.93 $2.32 $4.61 $2.99
Oil  Bbls 44,832 43,123 40,215 42,056 47,411
Average Price (per Bbl) $34.81 $26.11 $20.90 $24.99 $24.66


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 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 twelve 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. By correspondence dated March 25, 2004, BROG notified
ConocoPhillips of BROGs election to terminate such contract as of
March 31, 2005. BROG then prepared a form of request for proposal
and circulated it to a number of potential purchasers, including
ConocoPhillips, inviting them to bid for the purchase of the gas
currently sold under the contract expiring March 31, 2005. Effective
as of April 1, 2005, BROG entered into two new contracts for the
sale of all volumes of gas produced from the Underlying Properties
and formerly sold to ConocoPhillips. These new contracts provide
for (i) the sale of such gas to ChevronTexaco Natural Gas, a division of
Chevron U.S.A. Inc. and Coral Energy Resources, L.P., respectively,
(ii) the delivery of such gas at various delivery points through March
31, 2007, and from year-to-year thereafter until terminated by
either party on twelve months notice, and (iii) the sale of such gas at
prices which fluctuate in accordance with the published indices for
gas sold in the San Juan Basin of northwestern New Mexico. With
respect to PNM Gas Services, neither BROG nor PNM Gas Services
notified the other party of its desire to terminate the contract and,
accordingly, the PNM Gas Services contract has been extended until
March 31, 2006. See Note 6 of the Notes to Financial Statements
included herein for further information concerning the marketing of
gas produced from the Underlying Properties.

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.
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|R OYA LT Y INCOME
Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income for the five years ended December
31, 2004, was determined as shown in the following table:
u TRUSTEES DISCUSSION b ANALYSIS u u TRUSTEES DISCUSSION b ANALYSIS u
2004 2003 2002 2001 2000
GROSS PROCEEDS FROM THE
UNDERLYING PROPERTIES:
Gas $204,682,365 $175,653,183 $103,349,299 $169,052,231 $124,902,689
Oil 2,670,763 1,938,972 1,863,827 2,233,071 2,409,158
Other 3,314,808(1) (1,202,368)(2) (5,110,589)(3) -0- 4,653,333(4)
TOTAL $210,667,936 $176,389,787 $100,102,537 $171,285,302 $131,965,180
LESS PRODUCTION COSTS:
Capital Expenditures 22,338,684 20,590,704 21,470,777 32,999,973 25,575,657
Severance Tax  Gas 19,766,231 17,281,986 9,752,508 16,687,074 12,059,286
Severance Tax  Oil 253,022 174,750 151,594 202,113 234,462
Other 42,763 41,850 18,037 55,000 129,16
Lease Operating Expenses
and Property Taxes 20,210,213 15,637,481 15,701,740 15,109,139 13,906,916(5)
TOTAL 62,610,913 53,726,771 47,094,656 65,053,299 51,905,482
Excess Production Costs -0- -0- (2,259,628)(6) 2,259,628(6) -0-
Interest on Excess
Production Costs -0- -0- (10,545)(6) -0- -0-
Net Profits 148,057,023 122,663,016 50,737,708 108,491,631 80,059,698
Net Overriding
Royalty Interest 75% 75% 75% 75% 75%
Royalty Income $111,042,767 $91,997,262 $38,053,281 $81,368,723 $60,044,773
(1) Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions, interest received
for resolved audit exceptions, and insurance proceeds for a business
interruption claim.
(2) Represents a settlement between BROG and the Mineral Management Service of the United States Department of the Interior (the
MMS).
(3) 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
Trusts Annual Report on Form 10-K).
(4) 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.
(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 Underlying Properties 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 Trusts consultants have reviewed BROGs cost reporting data and confirmed that these additional charges
were appropriate.
(6) See Note 7 to the Financial Statements included herein.
DI S T RU B U TA B L E 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, 2004, Distributable Income
was $109,390,735, representing a 21% increase from 2003.
For the year ended December 31, 2003, Distributable Income
was $90,357,837, representing a 148% increase from 2002.
Distributable Income in 2002 was $36,417,967.
The Trust received Royalty Income of $111,042,767 and interest
income of $58,885 in 2004. After deducting administrative
expenses of $1,710,917, Distributable Income for 2004
was $109,390,735 ($2.346998 per Unit). In 2003, Royalty
Income was $91,997,262, interest income was $43,882, and
administrative expenses were $1,683,307, resulting in
Distributable Income of $90,357,837 ($1.938644 per Unit).
The 21% increase in Distributable Income from 2003 to 2004
was primarily attributable to higher gas and oil prices which
resulted in increased Royalty Income. Distributable Income for
2004 exceeds that for 2003 primarily due to higher gas and oil
prices. In addition, interest earnings in 2004 were higher,
as compared to 2003, primarily due to an increase in funds
available for investment as well as an increase in interest rates.
Administrative expenses were slightly higher in 2004, as
compared to 2003, primarily as a result of compliance with
the new internal control, financial reporting and other
requirements of the Sarbanes-Oxley Act of 2002.
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|In 2002, the Trust received Royalty Income of $38,053,281
and interest income of $16,112. After deducting administrative
expenses of $1,728,187 and including a decrease in cash
reserves of $76,761, Distributable Income for 2002 was
$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. 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 2003, as compared to 2002,
primarily as a result of differences in timing in the receipt and
payment of these expenses.
BROG has informed the Trustee that the New Mexico Oil and
Gas Proceeds Withholding Tax Act (the Withholding Tax
Act) requires remitters who pay certain oil and gas proceeds
from production on New Mexico properties on or after
October 1, 2003, to withhold income taxes from such
proceeds in the case of certain nonresident recipients. The
Trustee, on advice of counsel, has observed that net profits
interests, such as the Royalty, and other types of interests,
the extent of which cannot be determined with respect to a
specific share of the oil and gas production, are excluded from
the withholding requirements of the Withholding Tax Act.
Unit holders are reminded to consult with their tax advisors
regarding the applicability of New Mexico income tax to
distributions received from the Trust by a Unit holder.
OP E R AT I NG E X P E N S E S
Monthly operating expenses of the Underlying Properties,
exclusive of property taxes, in 2004 averaged approximately
$1,639,670, which is higher than the $1,250,600 average in
2003 and higher than the $1,262,900 average in 2002.
Operating expenses were higher in 2004 than for 2003
primarily because in calculating Royalty Income for October
2004, BROG allocated approximately $1.3 million of costs
incurred in the plugging and abandonment of wells from the
periods 1999 through January 2003. Operating expenses for
2000 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.
S E T T L E M E N T S
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 BROGs 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 twelve months ended June 30, 2002,
was estimated by the Trusts 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 BROGs 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 $12,500,000.
C A P I TA L E X P E N D I T U R E S
In February, 2004, BROG announced an estimated capital
budget for the Underlying Properties of approximately $18.5
million. However, BROG advised the Trust 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. BROGs
capital plan for the Underlying Properties for 2004 estimated
441 projects, including the drilling of 103 new wells to be
operated by BROG and 29 wells to be operated by third
parties. In 2004, BROG actually participated in 364 projects,
including 82 new wells operated by BROG and 32 wells operated
by third parties. BROG has indicated that, principally as a
result of the New Mexico Oil Conservation Divisions
approval of reduced, 160-acre spacing in the Fruitland Coal
formation, BROGs budget for 2004 reflected a continued
focus on that formation.
The aggregate capital expenditures reported by BROG in
calculating Royalty Income for 2004 include approximately
$10.8 million attributable to the capital budgets for prior
years. This occurs because projects within a given years 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,
BROGs accounting period for capital expenditures runs
through November 30 of each calendar year, such that capital
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|u TRUSTEES DISCUSSION b ANALYSIS u
expenditures incurred in December of each year are actually
accounted for as part of the following years capital expenditures.
In addition, with respect to wells not operated by BROG,
BROGs 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 $11.5
million for 2004 budgeted projects were used in calculating
net proceeds payable to the Trust in calendar year 2004, and
approximately $3.3 million in capital expenditures from the
2004 budget were used in calculating net proceeds payable to
the Trust for January and February 2005. Therefore, an
additional approximately $3.6 million in capital expenditures
for budgeted 2004 projects remains to be spent.
During 2004, in calculating Royalty Income, BROG deducted
approximately $22.3 million of capital expenditures for
projects, including drilling and completion of 25 gross (6.49
net) conventional wells, recompletion of 11 gross (8.05 net)
conventional wells, nine gross (5.95 net) restimulations,
three gross (0.007 net) conventional payadds, 61 gross (6.10
net) coal seam wells, four gross (3.41 net) coal seam
recompletions, and two gross (.05 net) miscellaneous coal
seam capital projects and facilities maintenance.
There were 57 gross (6.94 net) new conventional wells,
recompletion of three gross (.89 net) conventional wells, four
gross (2.24 net) conventional well restimulations, 13 gross
(1.74 net) conventional payadds, 48 gross (4.74 net) coal
seam wells, four gross (1.90 net) coal seam recompletions and
six gross (.27 net) miscellaneous coal seam capital projects in
progress as of December 31, 2004.
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, and 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 (3.65 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.
For 2005, BROGs announced plan for the Underlying
Properties includes 401 projects at an aggregate cost of
$17.0 million. Approximately $12.0 million of that budget is
allocable to new wells, with approximately 61% of those wells, at
an aggregate cost of approximately $5.4 million, projected to be
drilled to formations producing coal seam gas as distinguished
from conventional gas, and $4.9 million is to be expended in
working over existing wells and in themaintenance and
improvement of production facilities. 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
2005 could range from $15 million to $25 million. BROG has
announced that the budget for 2005 reflects the commencement
of a shift toward increased development of conventional gas
and a winding down of its program for infill drilling in the
Fruitland Coal formation.
BROG indicates its budget for 2005 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 2005
are projected to be drilled on 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.
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|u TRUSTEES DISCUSSION b ANALYSIS u
C O N T R AC T UA L OB L I G AT I O N S
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 Trustees 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).
EF F E C T S OF S E C U R I T I E S 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
(which contains many of the provisions of the Sarbanes-Oxley
Act of 2002) and the rules and regulations of the NYSE.
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)
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. It is the Trustees intention to
follow the Commissions and NYSEs 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. To date, the rules
implementing the Sarbanes-Oxley Act of 2002 have generally
made appropriate accommodation for passive entities such as
the Trust.
C R I T I C A L ACCOUN T I NG P O L I C I E S
In accordance with the Commissions staff accounting bulletins
and consistent with other royalty trusts, the financial statements
of the Trust are prepared on the following basis:
u Royalty Income recorded for a month is the amount
computed and paid by BROG to the Trustee for the Trust.
u Trust expenses recorded are based on liabilities paid and
cash reserves established from Royalty Income for liabilities
and contingencies.
u Distributions to Unit holders are recorded when declared
by the Trustee.
u 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-ofproduction
basis is charged directly to trust corpus instead of
an expense.

Archuleta LaPlata
Montezuma
Rio Arriba
San Juan
Sandoval
McKinley
C OLORAD O C OL ORAD O C OLORAD O
NEW MEXIC O NEW MEXIC O NEW MEXIC O
OIL FIELDS
MINERAL ACREAGE
GAS FIELDS
LEASEHOLD ACREAGE
SAN JUAN BASIN
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|u TRUSTEES DISCUSSION b ANALYSIS u
R E S U LT S O F T H E 4TH QUA RT E R S OF 2 0 0 4 AND 2003
For the three months ended December 31, 2004, Distributable Income was $29,305,430 ($.628753 per Unit), which was more
than the $21,419,523 ($.459559 per Unit) of income distributed during the same period in 2003. 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, 2004 and 2003 were as follows:
The average price of gas and oil increased in 2004 compared to the prior year. The price per barrel of oil during the fourth
quarter of 2004 was $16.78 per Bbl higher than that received in the fourth quarter of 2003 due to increases in oil prices in world
markets generally, including the posted price applicable to the Royalty. Gas production decreased slightly because new production
brought on line in 2004 failed to completely offset the natural decline in production from existing wells.
Capital costs for the fourth quarter of 2004 totaled $4,843,584 compared to $6,861,521 during the same period of 2003. The
decrease was primarily due to decreased drilling activity in the fourth quarter of 2004. Lease operating expenses and property taxes
for
the fourth quarter of 2004 averaged $2,168,935 per month compared to $1,163,120 per month in the fourth quarter of 2003.
Operating expenses were higher in the fourth quarter of 2004 than for the fourth quarter of 2003 primarily because in calculating
Royalty Income for October 2004, BROG allocated approximately $1.3 million of costs incurred in the plugging and abandonment
of wells from the periods 1999 through January 2003.
Based on 46,608,796 Units outstanding, the per Unit distributions during the fourth quarter of 2004 and 2003 were as follows:
2004 2003
October $ .214123 $ .143777
November .199538 .166295
December .215092 .149487
QUARTER TOTAL $ .628753 $ .459559

UNDERLYING PROPERTIES 2004 2003
Gas-Mcf 11,295,783 11,677,586
Mcf per Day 122,780 126,930
Average Price (per Mcf) $4.80 $3.71
Oil  Bbls 17,686 17,216
Bbls per Day 192 187
Average Price (per Bbl) $42.55 $25.77
ATTRIBUTABLE TO THE ROYALTY
Gas  Mcf 6,566,249 6,453,617
Oil  Bbls 10,223 9,532
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|ERNADETTE EUSTACE u In New Mexico, The Eustace name is synonymous with fine
jewelry. So its no surprise that Bernadette Eustace is a master of the art. At night by candlelight,
Bernadettes Zuni Indian father and Cochiti Indian mother would teach their thirteen children
the art of design and quality craftsmanship. Now, years later, the remaining nine children have
the skills they need to support themselves and contribute to their New Mexico heritage. Today,
Bernadette prides herself on designing jewelry thats as clean as it is beautiful. Its part of a promise
to herself and a dedication to her familys legacy.
WWW.PALACEOFTHEGOVERNORS.ORG
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|u SAN JUAN BASIN ROYALTY TRUST u
S TAT E M E N T S O F A S S E T S , L I A B I L I T I E S AND T RU S T C O R P U S
December 31, 2004 and 2003
S TAT M E N T S O F DI S T R I B U TA B L E INCOME
For the Three Years Ended December 31, 2004
S TAT E M E N T S O F CHANG E S I N T RU S T C O R P U S
For the Three Years Ended December 31, 2004
ASSETS 2004 2003
Cash and Short-Term Investments $ 10,140,045 $ 7,082,284
Net Overriding Royalty Interests in Producing Oil and Gas Properties  Net 26,674,821 29,822,820
TOTAL $ 36,814,866 $ 36,905,104
LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit holders $ 10,025,187 $ 6,967,426
Cash Reserves 114,858 114,858
Trust Corpus  46,608,796 Units of Beneficial Interest Authorized and Outstanding 26,674,821 29,822,820
TOTAL $ 36,814,866 $ 36,905,104
2004 2003 2002
Royalty Income $ 111,042,767 $ 91,997,262 $ 38,053,281
Interest Income 58,885 43,882 16,112
111,101,652 92,041,144 38,069,393
Expenditures  General and Administrative 1,710,917 1,683,307 1,728,187
Change in Cash Reserves  (76,761)
Distributable Income $109,390,735 $ 90,357,837 $ 36,417,967
Distributable Income per Unit (46,608,796 Units) $ 2.346998 $ 1.938644 $ 0.781354
2004 2003 2002
Trust Corpus, Beginning of Period $ 29,822,820 $ 33,697,906 $ 37,859,749
Amortization of Net Overriding Royalty Interest (3,147,999) (3,875,086) (4,161,843)
Distributable Income 109,390,735 90,357,837 36,417,967
Distribution Declared (109,390,735) (90,357,837) (36,417,967)
Trust Corpus, End of Period $ 26,674,821 $ 29,822,820 $ 33,697,906
These Financial Statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.
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|u NOTE S T O FINANCIAL STATEMENTS u
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 Southlands working interests and royalty interests
(the Underlying Properties) in the properties located in the San Juan Basin
in northwestern New Mexico.
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:
u 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;
u 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;
u The Trustee may establish a cash reserve for the payment of any liability
which is contingent or uncertain in amount;
u The Trustee is authorized to borrow funds to pay liabilities of the Trust; and
u 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 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 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
Southlands historical net book value at the date of the transfer of the Trust.
Accumulated amortization as of December 31, 2004 and 2003 aggregated
$106,600,707 and $103,452,708 respectively.
3. BASIS OF ACCOUNTING
The financial statements of the Trust are prepared on the following basis:
u 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%. Any adjustments to
the Royalty Income received from BROG are recorded by the Trust when
received and impact the distribution to Unit holders for that month.
u Trust expenses recorded are based on liabilities paid and cash reserves
established from Royalty Income for liabilities and contingencies.
u Distributions to Unit holders are recorded when declared by the Trustee.
u 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; expenses
are recorded when paid instead of when incurred; and amortization of the
Royalty calculated on a unit-of-production basis is charged directly to trust
corpus instead of an expense.
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|u NOTE S T O FINANCIAL STATEMENTS u
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 Trusts 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 conomic 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 but not thereafter.
Although Congress has at various times since 2002 considered energy legislation,
including provisions to reinstate the Section 29 credit in various ways and to
various extents, 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.
The classification of the Trusts 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 be subject to offset by 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 earnings thereon from September 5, 1996,
in settlement of underpayment of royalty claims of the Trust; and (ii)
commencing in 1997, to credit the Trust with $250,000 per year for five
years as an offset against lease operating expenses chargeable to the Trust.
BROG also agreed to make certain adjustments that represent cost reductions
favorable to the Trust in the ongoing charges for coal seam gas gathering and
treating on BROGs 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 BROGs 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 contracts 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 make a deduction for marketing fees associated
with sales of oil or natural gas liquids products.
c. The Trust retained access to BROGS current gas transportation,
gathering, processing and treating agreements with third parties
through the remainder of their primary terms.
6. CERTAIN CONTRACTS
BROG entered into two contracts for the sale of all gas from the Underlying
Properties. These contracts provide for (i) the sale of such 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. By correspondence dated March 25, 2004, BROG notified
ConocoPhillips of BROGs election to terminate such contract as of March
31, 2005. BROG then prepared a form of request for proposal and circulated
it to a number of potential purchasers, including ConocoPhillips, inviting
them to bid for the purchase of the gas currently sold under the contract
expiring March 31, 2005. Effective as of April 1, 2005, BROG entered into
two new contracts for the sale of all volumes of gas produced from the
Underlying Properties and formerly sold to ConocoPhillips. These new
contracts provide for (i) the sale of such gas to ChevronTexaco Natural Gas,
a division of Chevron U.S.A. Inc. and Coral Energy Resources, L.P.,
respectively, (ii) the delivery of such gas at various delivery points through
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|u NOTE S T O FINANCIAL STATEMENTS u
March 31, 2007, 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 the published indices for gas sold in the San Juan
Basin of northwestern New Mexico. With respect to PNM Gas Services,
neither BROG nor PNM Gas Services notified the other party of its desire to
terminate the contract and, accordingly, the PNM Gas Services contract has
been extended until March 31, 2006.
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. 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.
8. SIGNIFICANT CUSTOMERS
Information as to significant purchasers of oil and gas production attributable
to the Trusts economic interests is included in Note 6 above and Item 2 of
the Trusts Annual Report Form 10-K which is included in this report.
9. SETTLEMENTS
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 Trusts April 2003 royalty payment. This represents the Trusts 75%
interest of the total settlement.
During 2004, an aggregate of $3,314,808 was allocated to the Trust
by BROG as part of the ongoing negotiation of joint interest audit exceptions,
interest for resolved audit exceptions, and insurance proceeds for a
business interruption claim.
10. PROVED OIL AND GAS RESERVES (UNAUDITED)
Proved oil and gas reserve information is included in Item 2 of the Trusts
Annual Report on Form 10-K which is included in this report.
11. AMENDMENTS TO THE TRUSTS 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 Trusts 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.
12. 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, 2004 (in thousands,
except unit amounts):
DISTRIBUTABLE
INCOME AND
ROYALTY DISTRIBUTABLE DISTRIBUTION
INCOME INCOME PER UNIT
2004
First Quarter $ 21,196 $ 20,692 $ .443948
Second Quarter 25,509 24,992 .536204
Third Quarter 34,674 34,402 .738093
Fourth Quarter 29,663 29,305 .628753
TOTAL $ 111,042 $ 109,391 $ 2.346998
2003
First Quarter $ 19,911 $ 19,498 $ .418337
Second Quarter 26,051 25,619 .549655
Third Quarter 24,332 23,821 .511093
Fourth Quarter 21,703 21,420 .459559
TOTAL $ 91,997 $ 90,358 $ 1.938644
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|We have audited the accompanying statements of assets, liabilities and trust corpus of the San Juan
Basin Royalty Trust as of December 31, 2004 and 2003 and the related statements of Distributable
Income and changes in trust corpus for each of the three years in the period ended
December 31, 2004. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion
on these financial statements based on our audits. u
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
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. u
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. u
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust
corpus of the San Juan Basin Royalty Trust as of December 31, 2004 and 2003 and the Distributable Income and changes in
trust corpus for each of the three years in the period ended December 31, 2004, on the basis of accounting described in Note 3
to the financial statements. u
We have also audited in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the effectiveness of the Trusts internal control over financial reporting as of December 31, 2004, based on criteria established
in Internal Control  Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
and our report dated March 15, 2005, expressed an unqualified opinion thereon. u
WEAVER AND TIDWELL, L.L.P.
Fort Worth, Texas
March 15, 2005
S A N J UA N B A S I N R OYA LT Y T RU S T
TexasBank, Trustee
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas 76116
Toll-free telephone: 866-809-4553
www.sjbrt.com
sjt@texasbank.com
A U D I TO R S
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
L E G A L COUN S E L
Vinson  Elkins L.L.P.
Dallas, Texas
TA X COUN S E L
Winstead, Sechrest Minick, PC
Houston, Texas
T R A N S F E R AG E N T
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.
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|u GLO SSARY yTERMS u
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 60F.
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 noncapital
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.
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|SAN JUAN BASIN ROYALTY TRUST u TEXASBANK, TRUSTEE
2525 RIDGMAR BOULEVARD, SUITE 100 u FORT WORTH, TEXAS 76116 u 866.809.4553
WWW.SJBRT.COM
u
Santa Fe jeweler Liz Wallace contributed to the design of the 25th Anniversary cover piece.
This up-and-coming Indian artist combines cultural tradition with modern novelty to produce a distinctive Southwestern look.
To learn more about Lizs work visit www.shiprocktrading.com.
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