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EXHIBIT 13
 
 2005 A            NNUAL            R            EPORT & F            ORM 10-K
S            AN             J            UAN             B            ASIN             R            OYALTY            T            RUST 05




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MESAV            E R D E            N nbsp;           A T I O N A L            P            A R K
Deep in the heart of the southwest lies the spirit of the ancient
Anasazi people. Mesa Verde National Park is home to the cliff dwellings
these people constructed almost 1,000 years ago, using only their hands and
the natural resources available to them. Today, 24 Native American tribes
in the southwest have an ancestral af.liation with the sites at Mesa Verde.




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DISTRIBUTIONS
HIGH LOW PAID
First Quarter $ 37.4000 $ 27.7000 $ .831092
Second Quarter 44.2000 34.1000 .740612
Third Quarter 51.4300 39.0000 .692829
Fourth Quarter 49.2500 38.3000 .987214
T O T A L F O R 2 0 0 5 $ 3.251747
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
T O T A L F O R 2 0 0 4 $ 2.346998
At March 6, 2006, there were 46,608,796 Units outstanding held by 1,795 Unit holders of
record.
The following table presents information relating to the distribution of record ownership of Units:
NUMBER OF
T            Y P E O F            U            N I T            H            O L D E R S UNIT HOLDERS UNITS HELD
Individuals, Joint Holders and Minors 1,577 2,032,306
Fiduciaries 171 500,083
Government Bodies 6 1,331
Clubs, Associations or Societies 6 13,117
Depositary (for all bene.cial holders) 1 43,712,465
Corporations 34 349,494
T O T A L 1,795 46,608,796
2005
2004
1 TH E            T            R U S T
U N I T S O F            B            E N E F I C I A L            I            N T E R E S T
The units of bene.cial interest of the Trust (the Units) are traded on the New York Stock
Exchange
under the symbol SJT. At March 6, 2006, the closing price of a Unit was $39.20. From January 1,
2004, to
December 31, 2005, the quarterly high and low sales prices and the aggregate amount of monthly
distributions per
Unit paid each quarter were as follows:
T            H E P R I N C I P A L A S S E T            o            f 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.




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W            E ARE PLEASED TO PRESENT THE 2005 A            NNUAL            R            EPORT OF THE
S            AN             J            UAN             B            ASIN             R            OYALTY            T            RUST .
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, 2005, 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 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 and the successor, through a series of assignments and mergers,
to Southland Royalty
Company (Southland Royalty). 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 (the Underlying Properties) in properties in the San Juan Basin of northwestern
New Mexico.
On September 19, 2005, Compass Bancshares Inc. (Compass) announced the signing of a definitive
agreement to
acquire TexasBanc Holding Co. (TexasBanc), the parent company of the Trustee, in a combination
that would create
the fifth largest bank in Texas. The transaction, which is anticipated to be completed during the
first half of 2006, is
subject to all required regulatory approvals, approval by TexasBanc shareholders and other
customary conditions. On
December 12, 2005, ConocoPhillips and Burlington Resources, Inc., BROGs parent (Burlington),
announced that they
signed a definitive agreement under which ConocoPhillips would acquire Burlington. That transaction
is subject to
shareholder and regulatory approval and other customary terms and conditions. It is anticipated
that the transaction will
be completed during the first half of 2006. Assuming that both of the subject transactions are
completed, Compass Bank,
a subsidiary of Compass, would succeed TexasBank as Trustee under the terms of the Indenture and
ConocoPhillips (or a
subsidiary) would succeed Burlington as BROGs parent.
The Royalty constitutes the principal asset of the Trust. Under the Indenture governing the Trust,
the function of
TexasBank, as Trustee, is to collect the net proceeds attributable to the Royalty (Royalty
Income), to pay all expenses
and charges of the Trust, and then distribute the remaining available income to the Unit holders.
Income distributed to Unit
holders in 2005 was $151,560,081 or $3.251747 per Unit. Distributable Income for 2005 consisted of
Royalty Income
of $153,858,264 plus interest income of $167,367, less administrative expenses of $2,465,550.
Information about the
Trusts estimated pro
ved 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. Independent petroleum
engineers retained by
the Trust have estimated the Underlying Properties could remain productive well beyond the stated
production index of
approximately 9.8 years and BROG has published information observing that the San Juan Basin 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. 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.
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, 2006, and for the year ending December 31, 2006. Unit holders owning Units in nominee
name may obtain
monthly tax information from the Trustee upon request. For the 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, Trustee
B            Y : L            E E            A            N N             A            N D E R S O N
Vice President and Trust Officer
T            O            U            N I T            H            O L D E R S




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M            ESA            V            ERDE            N             ATIONAL            P            ARK
Look closely at the dwellings and it is clear the people who constructed
them were small in stature compared to their modern day relatives. In
fact, an average Ancestral Pueblan man was about 5  ́51/2 tall, while an
average woman was 5  ́11/2. Life spans were short, as well. Most people
lived an average of 32 to 34 years, while about 50 percent of the
children died before they reached the age of .ve.




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D            E S C R I P T I O N O F T H E            P            R O P E R T I E S
T            HE 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 4,429 gross (1,277 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, 2005, the
production index for the Underlying Properties is
estimated to be approximately 9.8 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 2005
production month was approximately 42.5% 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. BROG
reports that while there are currently no increased
density proposals before the OCD, BROG continues
to evaluate the merits of additional increased density
for each formation in the San Juan Basin.
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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T            R U S T E E  S            D            I S C U S S I O N & A            N A L Y S
I S
2005 2004 2003 2002 2001
Gas  Mcf 42,867,162 44,015,816 45,202,576 46,206,297 42,960,149
Mcf per Day 117,444 120,262 123,843 126,593 117,699
Oil  Bbls 69,558 77,341 74,727 93,659 92,413
Bbls per Day 191 211 205 257 253
Royalty Income for a calendar year is based on the actual gas and oil production during the
period beginning with November
of the preceding calendar year through October of the current calendar year. Gas and oil sales
attributable to the Royalty
for the past five years are summarized in the following table:
2005 2004 2003 2002 2001
Gas  Mcf 26,600,644 25,324,435 25,922,650 19,584,056 19,272,021
Average Price (per Mcf) $ 6.27 $ 4.68 $ 3.93 $ 2.32 $ 4.61
Oil  Bbls 43,142 44,832 43,123 40,215 42,056
Average Price (per Bbl) $ 49.62 $ 34.81 $ 26.11 $ 20.90 $ 24.99
G            A S A N D            O            I L            P            R O D U C T I O N
Total gas and oil production from the Underlying Properties for the five years ended December
31, 2005, were as follows:
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 previously entered into two contracts for the sale of
all volumes of gas produced from the Underlying Properties
providing 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) 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 (ConocoPhillips)
pursuant to an Assignment and Novation Agreement. By
correspondence dated March 25, 2004, BROG notified
ConocoPhillips of BROGs 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 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
BROGs contract with PNM Gas Services, BROG and PNM
Gas Services have entered into a letter agreement dated
January 31, 2005, pursuant to which the parties waive the
right to terminate the underlying contract as of March 31, 2006,
so that the term of that contract will continue until at least
March 31, 2007, and from year-to-year thereafter until
terminated by either party upon 12 months notice to the other.
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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T            R U S T E E  S            D            I S C U S S I O N & A            N A L Y S
I S
R            O Y A L T Y            I            N C O M E
Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income
for the five years
ended December 31, 2005, was determined as shown in the following table:
2005 2004 2003 2002 2001
Gas $ 267,895,460 $ 204,682,365 $ 175,653,183 $ 103,349,299 $ 169,052,231
Oil 3,451,115 2,670,763 1,938,972 1,863,827 2,233,071
Other 2,405,486 1 3,314,808 2 (1,202,368) 3 (5,110,589) 4 -0-
T O T A L $ 273,752,061 $ 210,667,936 $ 176,389,787 $ 100,102,537 $ 171,285,302
Capital Expenditures $ 19,127,698 $ 22,338,684 $ 20,590,704 $ 21,470,777 $ 32,999,973
Severance Tax  Gas 26,717,315 19,766,231 17,281,986 9,752,508 16,687,074
Severance Tax  Oil 362,023 253,022 174,750 151,594 202,113
Other 273,766 42,763 41,850 18,037 55,000
Lease Operating Expenses
and Property Taxes 22,126,907 20,210,213 15,637,481 15,701,740 15,109,139
T O T A L $ 68,607,709 $ 62,610,913 $ 53,726,771 $ 47,094,656 $ 65,053,299
Excess Production Costs -0- -0- -0- (2,259,628) 5 2,259,628 5
Interest on Excess
Production Costs -0- -0- -0- (10,545) 5 -0-
Net Profits $ 205,144,352 $ 148,057,023 $ 122,663,016 $ 50,737,708 $ 108,491,631
Net Overriding
Royalty Interest 75% 75% 75% 75% 75%
Royalty Income $ 153,858,264 $ 111,042,767 $ 91,997,262 $ 38,053,281 $ 81,368,723
(1) Represents funds allocated to the Trust as part of the ongoing negotiation of joint
interest audit exceptions.
(2) 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.
(3) Represents a settlement between BROG and the Mineral Management Service of the United
States Department of the Interior (the MMS).
(4) 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).
(5) Represents excess production costs incurred in December 2001 and recovered by BROG in
2002, plus interest.
G            
ROSS            P            ROCEEDS FROM THE
U            NDERLYING            P            ROPERTIES
L            ESS            P            RODUCTION             C            OSTS
D            I S T R I B U T A B L E            I            N C O M E
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, 2005, Distributable
Income was $151,560,081, representing a 38% increase
from 2004. For the year ended December 31, 2004,
Distributable Income was $109,390,735, representing a
21% increase from 2003. Distributable Income in 2003
was $90,357,837.
The Trust received Royalty Income of $153,858,264 and
interest income of $167,367 in 2005. After deducting
administrative expenses of $2,465,550, Distributable
Income for 2005 was $151,560,081 ($3.251747 per
Unit). In 2004, Royalty Income was $111,042,767, interest
income was $58,885, and administrative expenses were
$1,710,917, resulting in Distributable Income of
$109,390,735 ($2.346998 per Unit). The 38% increase
in Distributable Income from 2004 to 2005 was primarily
attributable to higher gas and oil prices which resulted in
increased Royalty Income. In addition, interest earnings in
2005 were higher, as compared to 2004, primarily due to
an increase in funds available for investment as well as an
increase in interest rates. Administrative expenses were




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T R U S T E E  S            D            I S C U S S I O N & A            N A L Y S
I S
higher in 2005, as compared to 2004, primarily as a result of compliance with the new internal control, financial
reporting and other requirements of the Sarbanes-Oxley Act
of 2002 and costs incurred in resolving certain outstanding
audit issues, including the costs of the arbitration referred to
in Note 7 to the Financial Statements included herewith.
In 2003, the Trust received Royalty Income of $91,997,262
and interest income of $43,882. After deducting administrative
expenses of $1,683,307, Distributable Income for 2003
was $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. 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.
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 New Mexico 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.
O            P E R A T I N G            E            X P E N S E S
Monthly operating expenses of the Underlying Properties,
exclusive of property taxes, in 2005 averaged approximately
$1,769,538, which is higher than the $1,639,670 average
in 2004 and higher than the $1,250,600 average in 2003.
Operating expenses were higher in 2005 than for 2004
primarily because increased activity strained the capacity of
service vendors and resulted in increasing costs. 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 2001
included 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
under Settlements below. The final $250,000 offset was
made in December 2001.
S            ET 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 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 $15,500,000.
C            A P I TA L            E            X P E N D I T U R E S
During 2005, in calculating Royalty Income, BROG deducted
approximately $19.1 million of capital expenditures for projects,
including drilling and completion of 38 gross (2.72 net)
conventional wells, five gross (0.011 net) payadds, one gross
(0.57 net) conventional restimulation, 25 gross (2.89 net)
coal seam wells, one gross (0.99 net) coal seam recavitation, two
gross (0.61 net) coal seam recompletions, and five gross
(0.20 net) miscellaneous coal seam capital projects.
The aggregate capital expenditures reported by BROG in
calculating Royalty Income for 2005 include approximately
$6 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




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T R U S T E E  S D I S C U S S I O N & A            N A L Y S
I S
attributable to those projects used in calculating Distributable
Income to the Trust in those subsequent years. Further,
BROGs accounting period for capital expenditures runs
through November 30 of each calendar year, such that
capital expenditures incurred in December of each year are
actually accounted for as part of the following years capital
expenditures. 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 $13.9 million for 2005 budgeted projects
were used in calculating net proceeds payable to the Trust
in calendar year 2005, and approximately $5.1 million in
capital expenditures from the 2005 budget were used in
calculating net proceeds payable to the Trust for January
and February 2006. Therefore, an additional approximately
$2.8 million in capital expenditures for budgeted 2005
projects remains to be spent.
There were 110 gross (19.08 net) conventional wells,
eight gross (1.73 net) payadds, six gross (3.30 net)
conventional recompletions, seven gross (5.04 net) conventional
restimulations, 59 gross (10.06 net) coal seam wells, five
gross (2.32 net) coal seam recompletions, and one gross
(0.04 net) miscellaneous coal seam capital project in
progress as of December 31, 2005.
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 (0.05 net) miscellaneous coal
seam capital projects and facilities maintenance. There were
57 gross (6.94 net) new conventional wells, recompletion of
three gross (0.89 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
(0.27 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. BROG has informed the Trust that its budget for capital
expenditures for the Underlying Properties in 2006 is
estimated at $37.6 million. Approximately $33 million of that
budget is allocable to 153 new wells, including 41 wells
scheduled to be dually completed in the Mesaverde and
Dakota formations at an aggregate projected cost of
approximately $13.6 million. BROG indicates that 61 of the
new wells, at an aggregate cost of approximately $16 million,
are projected to be drilled to formations producing coal seam
gas as distinguished from conventional gas, and $4.5 million
is to be expended in working over existing wells and in the
maintenance and improvement of production facilities.
BROG reports that based on its actual capital requirements,
the pace of regulatory approvals, and the mix of projects and
swings in the price of natural gas, the actual capital
expenditures for 2006 could range from $20 million to $45
million. BROG anticipates 451 projects, including the drilling
of 103 new wells to be operated by BROG and 50 wells to
be operated by third parties. Of the new BROG operated
wells, 52 are projected to be conventional wells completed
to the Pictured Cliffs, Mesaverde, and/or Dakota formations,
and the remaining 51 are projected as coal seam gas wells to
be completed in the Fruitland Coal formation. A total of 40
of the wells operated by third parties are projected to
be conventional wells, and the remaining 10 are to be
coal seam wells. BROG has announced that the budget for
2006 reflects the continuation of a shift toward increased
development of conventional gas.
C            O N T R AC T UA L            O            B L I GAT 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 Trustees standard hourly rates for time in excess of SAN JUAN BASIN
GAS FIELDS
OIL FIELDS
LEASEHOLD ACREAGE
Archuleta La Plata
Montezuma
Rio Arriba
San Juan
FARMINGTON
DURANGO
Sandoval
McKinley
COLORADO
NEW MEXICO




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9 T            R U S T E E  S            D            I S C U S S I O N & A            N
A L Y S I S
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).
E            F F E C T S O F            S            E C U R I T I E S R            E G U L AT I O N
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
Trustees intention to follow the Commissions and 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. 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            A            C C O U N T I N G            P            O L I C I E S
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:
· Royalty Income recorded for a month is the amount
computed and paid by BROG to the Trustee for the
Trust. Royalty Income consists of the proceeds received
by BROG from the sale of production from the
Underlying Properties less accrued production costs,
development and drilling costs, applicable taxes, operating
charges, and other costs and deductions, multiplied by
75%. The calculation of net proceeds by BROG for any
month includes adjustments to proceeds and costs for
prior months and impacts the Royalty Income paid to the
Trust and the distribution to Unit holders for that month.
· Trust expenses recorded are based on liabilities paid
and cash reserves established from Royalty Income for
liabilities and contingencies.
· Distributions to Unit holders are recorded when
declared by the Trustee.
· 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; 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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T            R U S T E E  S            D            I S C U S S I O N & A            N A L Y S
I S
R            E S U L T S O F T H E 4 T H            Q            U A R T E R S O F 2 0 0 5 & 2 0
0 4
For the three months ended December 31, 2005, Distributable Income was $46,012,856 ($.987214
per Unit), which was
more than the $29,305,430 ($.628753 per Unit) of income distributed during the same period in 2004.
The increase in
Distributable Income resulted primarily from higher average gas and oil prices.
Royalty Income of the Trust for the fourth quarter is based on actual gas and oil production during
August through October
of each year. Gas and oil sales for the quarters ended December 31, 2005 and 2004 were as follows:
2005 2004
Gas  Mcf 10,248,571 11,295,783
Mcf per Day 111,398 122,780
Average Price (per Mcf) $ 7.77 $ 4.80
Oil  Bbls 16,477 17,686
Bbls per Day 179 192
Average Price (per Bbl) $ 59.06 $ 42.55
Gas  Mcf 6,516,096 6,566,249
Oil  Bbls 10,429 10,223
The average price of gas and oil increased in 2005 compared to the prior year. The price per
barrel of oil during
the fourth quarter of 2005 was $16.51 per Bbl higher than that received in the fourth quarter of
2004 due to increases in
oil prices in world markets generally, including the posted price applicable to the Royalty. Gas
production decreased because
new production brought on line in 2005 failed to completely offset the natural decline in
production from existing wells.
In addition, production volumes were reduced in 2005 due to operational difficulties in the San
Juan Basin, including:
weather-related shut downs, pipeline maintenance work, compressor repairs and downtime at
processing facilities.
Capital costs for the fourth quarter of 2005 totaled $4,734,866 compared to $4,843,584 during the
same period of 2004.
Lease operating expenses and property taxes for the fourth quarter of 2005 averaged $1,939,447 per
month compared
to $2,168,935 per month in the fourth quarter of 2004. Operating expenses were lower in the fourth
quarter of 2005
than for the fourth quarter of 2004 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 2005
and 2004 were
as follows:
U            NDERLYING            P            ROPERTIES
A            TTRIBUTABLE TO THE            R            OYALTY
2005 2004
October $ .243762 $ .214123
November .334553 .199538
December .408899 .215092
Q U A R T E R T O T A L $ .987214 $ .628753 N             A V A J O            N             A T I O N A L            M            O N U M E N T
In another area of the southwest, the Navajo National Monument preserves three
of the most intact cliff dwellings of the Anasazi. These impressive multi-storied
structures tell us much about the people, except why they completely abandoned the
area by 1300 A.D. Whatever the reasons, the Anasazi people left behind a vast
network of architecture that included irrigation systems, elaborate ceremonial
chambers, ritualistic rock art images and ceramics.




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S A N J            U A N             B            A S I N             R            O Y A L T Y            T
R U S T
S            T A T 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 A N D
T            R U S T            C            O R P U S
December 31, 2005 & 2004
A            S S E T S 2005 2004
Cash and Short-Term Investments $ 19,173,162 $ 10,140,045
Net Overriding Royalty Interests in Producing Oil and Gas Properties  Net 23,881,494 26,674,821
T O T A L $ 43,054,656 $ 36,814,866
L            I A B I L I T I E S & T            R U S T            C            O R P U S 2005 2004
Distribution Payable to Unit holders $ 19,058,304 $ 10,025,187
Cash Reserves 114,858 114,858
Trust Corpus  46,608,796 Units of Beneficial Interest Authorized and Outstanding
23,881,494 26,674,821
T O T A L $ 43,054,656 $ 36,814,866
S            T A T E M E N T S O F            D            I S T R I B U T A B L E            I            N C O M E
For the three years ended December 31, 2005
2005 2004 2003
Royalty Income $ 153,858,264 $ 111,042,767 $ 91,997,262
Interest Income 167,367 58,885 43,882
154,025,631 111,101,652 92,041,144
Expenditures  General and Administrative 2,465,550 1,710,917 1,683,307
Distributable Income $ 151,560,081 $ 109,390,735 $ 90,357,837
Distributable Income per Unit (46,608,796 Units) $ 3.251747 $ 2.346998 $ 1.938644
S            T A T E M E N T S O F            C            H A N G E S I N             T            R U S T            C            O R P
U S
For the three years ended December 31, 2005
2005 2004 2003
Trust Corpus, Beginning of Period $ 26,674,821 $ 29,822,820 $ 33,697,906
Amortization of Net Overriding Royalty Interest (2,793,327) (3,147,999) (3,875,086)
Distributable Income 151,560,081 109,390,735 90,357,837
Distributions Declared (151,560,081) (109,390,735) (90,357,837)
Trust Corpus, End of Period $ 23,881,494 $ 26,674,821 $ 29,822,820
N             O T E S T O            F     
       I N A N C I A L            S            T A T E M E N T S
1. T            R U S T            O            R G A N I Z A T I O N             A            N D            P            R O V I S I O N S




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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)




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conveyed to the Trust a 75% net overriding royalty interest
(Royalty) carved out of Southlands 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:
· 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;
· 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;
· The Trustee may establish a cash reserve for the payment
of any liability which is contingent or uncertain in amount;
· The Trustee is authorized to borrow funds to pay liabilities
of the Trust; and
· The Trustee will make monthly cash distributions to Unit
holders (see Note 2). 2. Ne t Ove r r id in g Ro ya l t y In t e r e st a n d
Dist r ibu t io n To Un it Ho l d e r s
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, 2005 and 2004 aggregated $109,394,034
and $106,600,707, respectively.
3. B            A S I S            O            F            A            C C O U N T I N G
The financial statements of the Trust are prepared on the
following basis:
· Royalty Income (as defined in the Glossary of Terms)
recorded for a month is the amount computed and paid by
the owner of the Underlying Properties, Burlington
Resources Oil & Gas Company LP (BROG), the present
owner of the Underlying Properties, to the Trustee for
the Trust. Royalty Income consists of the proceeds
received by BROG from the sale of production less
accrued production costs, development and drilling costs,
applicable taxes, operating charges, and other costs and
deductions, multiplied by 75%. The calculation of net
proceeds by BROG for any month includes adjustments
to proceeds and costs for prior months and impacts the
Royalty Income paid to the Trust and the distribution to
Unit holders for that month.
· Trust expenses recorded are based on liabilities paid and
cash reserves established from Royalty Income for liabilities
and contingencies.
· Distributions to Unit holders are recorded when declared
by the Trustee.
· 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 proceeds
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 These Financial Statements should
be read in conjunction with the accompanying Notes to Financial Statements included herein.




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N             O T E S T O            F            I N A N C I A L            S            T A T E M E N T S
a unit-of-production basis is charged directly to trust corpus
instead of an expense. The basis of accounting used by the
Trust is widely used by royalty trusts for financial purposes.
4. Fe d e r a l In c o me Ta xe s
For federal income tax purposes, the Trust constitutes a
fixed investment trust which is taxed as a grantor trust. A
grantor trust is not subject to tax at the trust level. The Unit
holders are considered to own the Trusts income and principal
as though no trust were in existence. The income of the
Trust is deemed to have been received or accrued by each
Unit holder at the time such income is received or accrued by
the Trust rather than when distributed by the Trust.
The Royalty constitutes an economic interest in oil and gas
properties for federal income tax purposes. Unit holders
must report their share of the revenues of the Trust as
ordinary income from oil and gas royalties and are entitled to
claim depletion with respect to such income. The Royalty is
treated as a single property for depletion purposes. The
Trust has on file technical advice memoranda confirming
such tax treatment.
Sales of gas production from coal seam wells drilled prior to
January 1, 1993, qualified for federal income tax credits
under Section 29 of the Internal Revenue Code of 1986, as
amended, through 2002, but not thereafter. Accordingly,
under present law, the Trusts production of gas from coal
seam wells does not qualify for the Section 29 tax credit.
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, but no legislation
that would qualify the Trusts current production for such
credit has been enacted. Most recently, for example, on
August 8, 2005, new energy tax legislation was enacted
which, among other things, modifies the Section 29 credit in
several respects, but does not extend the credit for production
from coal seam wells. No prediction can be made as to what
future tax legislation affecting Section 29 may be proposed
or enacted or, if enacted, its impact, if any, on the Trust and
the Unit holders.
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. C            E R T A I N             C            O N T R A C T S
BROG previously entered into two contracts for the sale of
all volumes of gas produced from the Underlying Properties
providing 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) 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 (ConocoPhillips)
pursuant to an Assignment and Novation Agreement. By
correspondence dated March 25,
2004, BROG notified
ConocoPhillips of BROGs 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 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 BROGs contract with PNM Gas Services, BROG and
PNM Gas Services have entered into a letter agreement
dated January 31, 2005, pursuant to which the parties
waive the right to terminate the underlying contract as of
March 31, 2006, so that the term of that contract will
continue until at least March 31, 2007, and from year-to-year
thereafter until terminated by either party upon 12 months
notice to the other.
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.
6. S            I G N I F I C A N T            C            U S T O M E R S
Information as to significant purchasers of oil and gas
production attributable to the Trusts economic interests is




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N             O T E S T O            F            I N A N C I A L            S            T A T E M E N T S
included in Note 5 above and Item 2 of the Trusts Annual
Report on Form 10-K which is included in this report.
7. S            E T T L E M E N T S A N D            L            I T I G A T I O N
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. The Trust reviewed the
propriety of this deduction with its consultants and it became
one of the issues submitted to the arbitration described
below in this Note 7.
During 2004, an aggregate of $3,314,808 was included in
calculating net proceeds paid 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.
In 2005, as part of the ongoing negotiations between the
Trust and BROG concerning a number of revenue and
expense audit issues, an aggregate of $2,405,486 was
included in calculating net proceeds BROG paid to the Trust
in settlement of certain of those audit issues.
On November 11, 2005, an Arbitration Award was issued
in favor of the Trust in the aggregate amount of $7,683,699
in arbitration styled San Juan Basin Royalty Trust vs. Burlington
Resources Oil & Gas Company LP.The purpose of the arbitration
was to resolve certain joint interest audit issues as between
the parties to the arbitration. On November 21, 2005, BROG filed its Original Petition to Vacate or to Modify or
Correct Arbitration Award in the cause styled Burlington
Resources Oil & Gas Company LP vs. San Juan Basin Royalty
Trust,No. 2005-74370, in the District Court of Harris
County, Texas, 281st Judicial District. In this litigation,
BROG alleges that the award in favor of the Trust should be
vacated or modified because one of the issues decided was
beyond the scope of the matters agreed to be arbitrated, the
award was issued in manifest disregard of applicable law, and
a portion of the award is barred by limitations. BROG also
seeks to recover its attorneys fees. The Trust has filed an
answer and counterclaim in the litigation filed by BROG
denying those allegations and asking that the arbitrators award
be confirmed.
8. P            R O V E D            O            I L            A            N D            G            A S            R            E S E R V E S ( U N A
U D I T E D )
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.
9. Q            U A R T E R L Y            S            C H E D U L E            O            F            D            I S T R I B U T A B L E
I            N C O M E ( U N A U D I T E D )
The following is a summary of the unaudited quarterly schedule of Distributable Income for the
two years ended
December 31, 2005 (in thousands, except unit amounts):
DISTRIBUTABLE
ROYALTY DISTRIBUTABLE INCOME AND
INCOME INCOME DISTRIBUTION PER UNIT
First Quarter $ 39,242 $ 38,736 $ .831092
Second Quarter 35,296 34,519 .740612
Third Quarter 32,833 32,292 .692829
Fourth Quarter 46,487 46,013 .987214
T O T A L $ 153,858 $ 151,560 $ 3.251747
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
T O T A L $ 111,042 $ 109,391 $ 2.346998
2005
2004




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W            E H AV E AU DI TED TH E AC C OMPA N Y I NG STATEMEN TS            of assets, liabilities and
trust corpus of the
San Juan Basin Royalty Trust as of December 31, 2005 and 2004 and the related statements of
Distributable Income
and changes in trust corpus for each of the three years in the period ended December 31, 2005.
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 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.
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, 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, 2005 and 2004 and the
Distributable
Income and changes in trust corpus for each of the three years in the period ended December 31,
2005, on the basis
of accounting described in Note 3 to the financial statements.
We have also audited in accordance with the standards of the Public Company Accounting Oversight
Board (United
States), the effectiveness of the Trusts internal control over financial reporting as of December
31, 2005, based on
criteria established in Internal Control  Integrated Frameworkissued by the Committee of
Sponsoring Organizations of
the Treadway Commission and our report dated March 10, 2006, expressed an unqualified opinion
thereon.
W            EAVER AND            T            IDWELL      , L.L.P.
Fort Worth, Texas
March 10, 2006




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R            E P O R T O F            I            N D E P E N D E N T
R            E G I S T E R E D            P            U B L I C            A            C C O U N T I N G            F
I R M            G            L O S S A R Y O F            T            E R M S
A            GGREGATE            M            ONTHLY            D            ISTRIBUTION : 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°F.
BCF: Billion cubic feet.
BROG: Burlington Resources Oil & Gas Company LP.
BTU: British thermal unit; the amount of heat necessary to raise the
temperature of one pound of water one degree Fahrenheit.
C            OAL            S            EAM            W            ELL : A well completed to a coal deposit found to
contain and emit natural gas.
C            OMMINGLED            W            ELL : A well which produces from two or more formations through a common well casing and a single tubing string.
C            ONVENTIONAL            W            ELL : 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.
D            EPLETION : 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.
D            ISTRIBUTABLE            I            NCOME : 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.
D            UAL            C            OMPLETION : 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.
E            STIMATED            F            UTURE            N             ET            R            EVENUES : 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.
G            RANTOR            T            RUST : 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.
G            ROSS            A            CRES            O            R            W            ELLS : The interests of all persons owning
interests in such acres or wells.
G            ROSS            P            ROCEEDS : The amount received by BROG (or any
subsequent owner of the Underlying Properties) from the sale of
the production attributable to such interests.
I            NFILL            D            RILLING : 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.
L            EASE            O            PERATING            E            XPENSES : 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.
M             ULTIPLE            C            OMPLETION             W            ELL : A well which produces simultaneously
through separate tubing strings from two or more producing
horizons or alternatively from each.
N             ET            A            CRES OR            W            ELLS : The interests of BROG in such acres or wells.
N             ET            O            VERRIDING            R            OYALTY            I            NTEREST : 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.
N             ET            P            ROCEEDS : The excess of Gross Proceeds received by BROG
during a particular period over Production Costs for such period.
P            AYADD : Completion in an existing well of additional productive
zone(s) within a producing formation.
P            RESENT            V            ALUE            O            F            E            STIMATED            F            UTURE            N             ET
R            EVENUES : The present
value of the Estimated Future Net Revenues computed using a
discount rate of 10%.
P            RODUCTION             C            OSTS : 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.
P            ROVED            D            EVELOPED            R            ESERVES : Those Proved Reserves which can
be expected to be recovered through existing wells with existing
equipment and operating methods.
P            ROVED 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.
P            ROVED            U            NDEVELOPED            R            ESERVES : 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.
R            ECAVITATED            W            ELL : 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.
R            ECOMPLETED            W            ELL : 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.
R            OYALTY : 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.
R            OYALTY            I            NCOME : The monthly Net Proceeds attributable to the
Royalty.
S            ECTION 29 T            AX            C            REDIT : 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.
S            POT            P            RICE : The price paid for gas, oil or oil products sold
under contracts for the purchase and sale of such minerals on a shortterm
basis.
U            NDERLYING            P            ROPERTIES : 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.
U            NITS OF            B            ENEFICIAL            I            NTEREST : 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.
W            ORKING            I            NTEREST : The operating interest under an oil and gas lease.
S            A N             J            U A N             B            A S I N             R            O Y A L T Y            T            R U 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 T O R S
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
L            E G A L            C            O U N S E L
Vinson & Elkins L.L.P.
Dallas, Texas
T            A X            C            O U N S E L
Winstead, Sechrest & Minick, PC
Houston, Texas
T            R A N S F E R            A            G E N T
Computershare Investor Services
Transfer Services
P.O. Box A3480
Chicago, Illinois 60609-3480




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##### 



S            A N             J            U A N             B            A S I N             R            O Y A L T Y            T            R U 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
O            N T H E            C            O V E R : Kiva interior, Mesa Verde National Park.