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SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549




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Form 10-K

|           |  |                                                                                           
|---------- |  | ------------------------------------------------------------------------------------------
|(Mark One) |  |                                                                                           
|þ          |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR
	15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934    
|          
|           |  | For the fiscal year ended December 31,
	2001,                                             
|          
|or        
|          
|o          |  | TRANSITION REPORT PURSUANT TO SECTION 13
	OR 15(d)
	OF THE SECURITIES EXCHANGE ACT OF 1934
|          
|           |  | For the transition period
	from           to                                              

Commission file number 1-8032

San Juan Basin Royalty Trust

(Exact name of registrant as specified in the
San Juan Basin Royalty Trust Indenture)


|                                                                                                                       |  |                                         
|---------------------------------------------------------------------------------------------------------------------- |  | ----------------------------------------
|Texas                                                                                                                  |  | 75-6279898                              
|(State or other jurisdiction of
	incorporation or organization)                                                        |  | (I.R.S. Employer
	Identification Number)
|Bank One, N.A.
	Corporate Trust Department
	P.O. Box 2604
	Fort Worth, Texas(Address of principal executive
	officers) |  | 76113(Zip Code)                         

(817) 884-4630

(Registrants telephone number, including
area code)


Securities registered pursuant to
Section 12(b) of the Act:

|                             |  |                                          
|---------------------------- |  | -----------------------------------------
|Title of Each Class          |  | Name of Each Exchange on Which Registered
|                             |  |                                          
|Units of Beneficial Interest |  | New York Stock Exchange                  

Securities registered Pursuant to
Section 12(g) of the Act:

None


(Title of Class)


Indicate by check mark whether the registrant
(1) has filed all reports required to be filed by
Section 13 or 15(d) of the Securities Exchange Act of 1934
during the preceding 12 months (or for such shorter period
that the registrant was required to file such reports), and
(2) has been subject to such filing requirements for the
past
90 days.    Yes þ         No o

Indicate by check mark if disclosure of
delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of
registrants knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this
Form 10-K or any amendment to this
Form 10-K.    þ

At March 28, 2002, there were 46,608,796
Units of Beneficial Interest of the Trust outstanding with an
aggregate market value on that date of $554,644,672.

DOCUMENTS INCORPORATED BY REFERENCE

Units of Beneficial Interest at
page 1; Description of the Properties at
pages 5 and 6; Trustees Discussion and
Analysis at pages 7 and 8; Results of the
4th Quarters of 2001 and 2000 at page 9; and
Statements of Assets, Liabilities and Trust Corpus,
Statements of Distributable Income, Statements
of Change in Trust Corpus, Notes to Financial
Statements, and Independent Auditors
Report at page 10 et seq., in registrants
Annual Report to Unit holders for fiscal year ended
December 31, 2001 are incorporated herein by reference for
Item 2 (Properties), Item 3 (Legal Proceedings),
Item 5 (Market for Units of the Trust and Related Security
Holder Matters), Item 7 (Managements Discussion and
Analysis of Financial Condition and Results of Operation) and
Item 8 (Financial Statements and Supplementary Data) of
Part II of this Report.



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TABLE OF CONTENTS



|                                                 |                                                                                              |  |  |  |  |  |  | 
|------------------------------------------------ | -------------------------------------------------------------------------------------------- |  |  |  |  |  |  | 
|PART I                                          
|                                                 | Item 1. Business                                                                            
|                                                 | Item 2. Properties                                                                          
|                                                 | Item 3. Legal Proceedings                                                                   
|                                                 | Item 4. Submission of Matters to a Vote of Security Holders                                 
|PART II                                         
|                                                 | Item 5. Market for Units of the Trust and Related Security Holder Matters                   
|                                                 | Item 6. Selected Financial Data                                                             
|                                                 | Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation
|                                                 | Item 7A. Quantitative and Qualitative Disclosure About Market Risk                          
|                                                 | Item 8. Financial Statements and Supplementary Data                                         
|                                                 | Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
|PART III                                        
|                                                 | Item 10. Directors and Executive Officers of the Registrant                                 
|                                                 | Item 11. Executive Compensation                                                             
|                                                 | Item 12. Security Ownership of Certain Beneficial Owners and Management                     
|                                                 | Item 13. Certain Relationships and Related Transactions                                     
|PART IV                                         
|                                                 | Item 14. Exhibits, Financial Statement Schedules and Reports On Form 8-K                    
|SIGNATURE                                       
|EXHIBIT INDEX                                   
|EX-13 Annual Report to Security Holders         
|EX-23.1 Consent of Cawley Gillespie & Associates



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PART I




Item 1.     Business

The San Juan Basin Royalty Trust (the
Trust) is an express trust created under the laws of
the state of Texas by the San Juan Basin Royalty
Trust Indenture (the Trust Indenture) entered
into on November 3, 1980, between Southland Royalty Company
(Southland Royalty) and The Fort Worth National
Bank, a banking association organized under the laws of the
United States, as Trustee. The Trustee is now Bank One, N.A. The
principal office of the Trust (sometimes referred to herein as
the Registrant) is located at 500 Throckmorton
Street, Fort Worth, Texas 76102, Attention: Corporate
Trust Department (telephone number (817) 884-4630).

On October 23, 1980, the stockholders of
Southland Royalty approved and authorized that companys
conveyance of a net overriding royalty interest (equivalent to a
net profits interest) to the Trust for the benefit of the
stockholders of Southland Royalty of record at the close of
business on the date of the conveyance consisting of a 75% net
overriding royalty interest carved out of that companys
oil and gas leasehold and royalty interests in the San Juan
Basin of northwestern New Mexico. The conveyance of this
interest (the Royalty) was made on November 3,
1980, effective as to production from and after November 1,
1980 at 7:00 A.M.

The Royalty was carved out of and now burdens
those properties and interests as more particularly described
under Item 2. Properties herein.

The Royalty constitutes the principal asset of
the Trust and the beneficial interests in the Royalty are
divided into that number of Units of Beneficial Interest (the
Units) of the Trust equal to the number of shares of
the common stock of Southland Royalty outstanding as of the
close of business on November 3, 1980. Each stockholder of
Southland Royalty of record at the close of business on
November 3, 1980 received one Unit for each share of the
common stock of Southland Royalty then held.

The function of the Trustee is to collect the
income attributable to the Royalty, to pay all expenses and
charges of the Trust, and then distribute the remaining
available income to the Unit holders. The Trust is not empowered
to carry on any business activity and has no employees, all
administrative functions being performed by the Trustee.

In 1985, Southland Royalty became a wholly-owned
subsidiary of Burlington Northern Inc. (BNI). In
1988, BNI transferred its natural resource operations to
Burlington Resources Inc. (BRI) as a result of which
Southland Royalty became a wholly-owned indirect subsidiary of
BRI. As a result of these transactions, El Paso Natural Gas
Company, Meridian Oil, Inc. (MOI) and Meridian Oil
Trading Inc. also became indirect subsidiaries of BRI. Effective
January 1, 1996, Southland Royalty, a wholly-owned
subsidiary of MOI, was merged with and into MOI, by which action
the separate corporate existence of Southland Royalty ceased and
MOI survived and succeeded to the ownership of all of the
assets, has the rights, powers and privileges and assumed all of
the liabilities and obligations of Southland Royalty. Subsequent
to the merger, MOI changed its name to Burlington Resources
Oil & Gas Company LP (BROG).

The term net proceeds, as used in the
November 3, 1980 conveyance, means the excess of
gross proceeds received by BROG during a particular
period over production costs for such period.
Gross proceeds means the amount received by BROG (or
any subsequent owner of the interests from which the Royalty was
carved) from the sale of the production attributable to the
interests in properties from which the Royalty was carved (the
Underlying Properties), subject to certain
adjustments. Production costs generally means costs
incurred on an accrual basis by BROG in operating its properties
and interests out of which the Royalty was carved, including
both capital and non-capital costs. For example, these costs
include development drilling, production and processing costs,
applicable taxes, and operating charges. If production costs
exceed gross proceeds in any month, the excess is recovered out
of future gross proceeds prior to the making of further payment
to the Trust, but the Trust is not otherwise liable for any
production costs or other costs or liabilities attributable to
these properties and interests or the minerals produced
therefrom. If at any time the Trust receives more than the
amount due under the Royalty, it shall not be obligated to
return such

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overpayment, but the amounts payable to it for
any subsequent period shall be reduced by such amount, plus
interest, at a rate specified in the conveyance.


Certain of the Underlying Properties are operated
by BROG with the obligation to conduct its operations in
accordance with reasonable and prudent business judgment and
good oil and gas field practices. As operator, BROG has the
right to abandon any well, when in its opinion, such well ceases
to produce or is not capable of producing oil and gas in paying
quantities. BROG also is responsible, subject to the terms of a
settlement agreement with the Trust, for marketing the
production from such properties, either under existing sales
contracts or under future arrangements at the best prices and on
the best terms it shall deem reasonably obtainable in the
circumstances. BROG also has the obligation to maintain books
and records sufficient to determine the amounts payable to the
Trustee. BROG, however, can sell its interest in the Underlying
Properties.

Proceeds from production in the first month are
generally received by BROG in the second month, the net proceeds
attributable to the Royalty are paid by BROG to the Trustee in
the third month and distribution by the Trustee to the Unit
holders is made in the fourth month. The identity of Unit
holders entitled to a distribution will generally be determined
as of the last business day of each calendar month (the
monthly record date). The amount of each monthly
distribution will generally be determined and announced ten days
before the monthly record date. Unit holders of record as of the
monthly record date will be entitled to receive the calculated
monthly distribution amount for each month on or before ten
business days after the monthly record date. The aggregate
monthly distribution amount is the excess of (i) net
revenues from the Trust properties, plus any decrease in cash
reserves previously established for contingent liabilities and
any other cash receipts of the Trust over (ii) the expenses
and payments of liabilities of the Trust plus any net increase
in cash reserves for contingent liabilities.

Cash being held by the Trustee as a reserve for
liabilities or contingencies (which reserves may be established
by the Trustee in its discretion) or pending distribution is
placed, in the Trustees discretion, in obligations issued
by (or unconditionally guaranteed by) the United States or any
agency thereof, repurchase agreements secured by obligations
issued by the United States or any agency thereof, or
certificates of deposit of banks having capital, surplus and
undivided profits in excess of $50,000,000, subject, in each
case, to certain other qualifying conditions.

The Underlying Properties are primarily gas
producing properties. Normally there is a greater demand for gas
in the winter months than during the rest of the year.
Otherwise, the income to the Trust attributable to the Royalty
is not subject to seasonal factors nor in any manner related to
or dependent upon patents, licenses, franchises or concessions.
The Trust conducts no research activities.

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




Item 2.     Properties

The 75% net overriding royalty conveyed to the
Trust was carved out the Underlying Properties, which consist of
Southland Royaltys (now BROGs) working interests and
royalty interests in properties situated in the San Juan
Basin in northwestern New Mexico. References below to
gross wells and acres are to the interests of all
persons owning interests therein, while references to
net are to the interests of BROG (from which the
Royalty was carved) in such wells and acres.

Unless otherwise indicated, the following
information in Item 2 is based upon data and information
furnished to the Trustee by BROG.

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Producing Acreage, Wells and
Drilling

The Underlying Properties consist of working
interests and royalty interests in 151,900 gross
(119,000 net) producing acres in San Juan, Rio Arriba
and Sandoval Counties of northwestern New Mexico. Based upon
information received from the Trusts independent petroleum
engineers, the Trust properties contain 3,305 gross
(976 net) economic wells, including dual completions.
Production from conventional gas wells is primarily from the
Pictured Cliffs, Mesaverde and Dakota formations. During 1988,
Southland Royalty began development of coal seam reserves in the
Fruitland Coal formation. For additional information concerning
coal seam gas, the Description of the Properties
section of the Trusts Annual Report to security holders
for the year ended December 31, 2001, is herein
incorporated by reference.

The Royalty conveyed to the Trust is limited to
the base of the Dakota formation, which is currently the deepest
significant producing formation under acreage affected by the
Royalty. Rights to production, if any, from deeper formations
are retained by BROG.

BROG revised its 2001 capital budget estimate for
the Underlying Properties upward from $30.2 million to
$38.8 million. BROGs capital plan for the Underlying
Properties for 2001 estimated 406 projects, including the
drilling of 49 new wells operated by BROG. In 2001, BROG
actually participated in 663 projects, including 61 new
wells operated by BROG. BROG informed the Trust that the upward
revision was due to the fact that service costs had been
expected to increase approximately 10% in 2001 as compared to
the prior year. However, BROG indicates that as a result of
higher commodity prices in 2001 and a resulting increased demand
for equipment and services, some costs actually increased in
2001 by as much as 40%. In addition, the Bureau of Land
Management has undertaken an environmental impact study of the
entire San Juan Basin such that new drilling activity
located more than 300 feet from an existing road now
requires an additional level of regulatory approval on a
well-by-well basis. More regulatory approvals to drill were
obtained in 2001 than expected, which resulted in an increase in
drilling activity.

The aggregate capital expenditures reported by
BROG in calculating distributable income for 2001 include
approximately $9,250,000 attributable to the capital budgets for
1999 and 2000. This occurs because projects within a given
years budget may extend into subsequent years, with
capital expenditures attributable to those projects used in
calculating distributable income to the Trust in those
subsequent years. Further, BROGs accounting period for
capital expenditures runs through November 30 of each
calendar year, such that capital expenditures incurred in
December of each year are actually accounted for as part of the
following years capital expenditures. Also, for wells not
operated by BROG, BROGs share of capital expenditures may
not actually be paid by it until the year or years after those
expenses were incurred by the operator. Capital expenditures of
approximately $27 million for 2001 budgeted projects were
used in calculating distributable income in calendar year 2001,
and approximately $7 million in capital expenditures have
been used in calculating distributions for the first two months
of 2002. Therefore, an additional approximately
$4.8 million in capital expenditures for 2001 projects
remains to be spent.

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

During 2000, in calculating the net proceeds to
the Trust, BROG deducted approximately $25.6 million of
capital expenditures for projects, including drilling and
completion of 45 gross (25.45 net) conventional wells,
recompletion of 15 gross (6.80 net) conventional
wells, 12 gross (6.75 net) coal seam wells,
4 gross (.17 net) coal seam well recompletions,
41 gross (.24 net) coal seam recavitations, and
facilities maintenance.

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There were 124 gross (36.15 net) new
conventional wells, 59 gross (21.37 net) conventional
well recompletions, 10 gross (2.14 net) coal seam
wells, 12 gross (1.64 net) coal seam recompletions,
and 4 gross (.03 net) coal seam recavitations in
progress as of December 31, 2000.


BROG has informed the Trust that it has reduced
its projections for capital expenditures for the Underlying
Properties for 2002 from an estimated $17.1 million to an
estimated $12.4 million. BROG anticipates the drilling of
43 new wells to be operated by BROG and 26 wells to be
operated by third parties. Of the new BROG operated wells, 36
are projected to be conventional wells completed to the Pictured
Cliffs, Mesaverde, and/or Dakota formations, and the remaining
seven are projected as coal seam gas wells to be completed in
the Fruitland Coal formation. BROG projects approximately
$9.6 million to be spent on the new wells, and
$2.8 million to be expended in working over existing wells
and in the maintenance and improvement of production facilities.

In February 2002, BROG informed the Trust that
the New Mexico Oil Conservation Division had approved plans for
80-acre infill drilling of the Dakota formation in the
San Juan Basin. Eighty-acre spacing has been permitted in
the Mesaverde formation since 1997. The Mesaverde formation was
originally developed in the 1950s on 320-acre spacing,
with infill drilling initiated in the early 1970s on
160-acre spacing. In 1994, BROG undertook an extensive study of
the Mesaverde formation. Results indicated that downspaced
drilling (infill drilling) on 80-acre spacing could
significantly increase recoverable gas reserves in this
reservoir. A pilot program began in 1997 and was expanded in
1998 to include two additional areas.

BROG has previously informed the Trust that
increases in its capital program, particularly in 2000 and 2001,
were designed to offset the natural decline in production from
the Underlying Properties. BROG has reported favorable results
in this effort in that natural gas production for calendar year
2001 averaged approximately 121 MMcf per day, as compared
to average production of approximately 116 MMcf per day for
calendar 2000 and 113 MMcf per day for calendar 1999.

BROG indicates its budget for 2002 reflects
continued, significant development of properties in which the
Trusts net overriding royalty interest is relatively high,
as well as a sustained focus on conventional formations,
including infill drilling to the Mesaverde and Dakota
formations, development of the Fruitland Coal formation and
multiple formation completions.

Oil and Gas Production

The Trust recognizes production during the month
in which the related distribution is received. Production of oil
and gas and related average sales prices attributable to the
Royalty for the three years ended December 31, 2001 were
as follows:

|              |  |        |        |       |  |        |            |       |  |        |        |       |  |   |            |  |  |   |        |  |  |   |            | 
|------------- |  | ------ | ------ | ----- |  | ------ | ---------- | ----- |  | ------ | ------ | ----- |  | - | ---------- |  |  | - | ------ |  |  | - | ---------- | 
|              |  |        |        |       |  |       
|              |  | 2001   |        | 2000  |  | 1999  
|              |  |        |        |       |  |       
|              |  | Oil    |        | Gas   |  | Oil    |            | Gas   |  | Oil    |        | Gas  
|              |  | (Bbls) |        | (Mcf) |  | (Bbls) |            | (Mcf) |  | (Bbls) |        | (Mcf)
|              |  |        |        |       |  |        |            |       |  |        |        |      
|Production    |  |        | 42,056 |       |  |        | 19,272,021 |       |  |        | 47,441 |       |  |   | 20,317,750 |  |  |   | 35,341 |  |  |   | 19,527,666 | 
|Average Price |  | $      | 24.99  |       |  | $      | 4.61       |       |  | $      | 24.66  |       |  | $ | 2.99       |  |  | $ | 14.41  |  |  | $ | 1.78       | 

Pricing Information

Gas produced in the San Juan Basin is sold
in both interstate and intrastate commerce. Reference is made to
Regulation for information as to federal regulation
of prices of oil and natural gas. Gas production from the
properties from which the Royalty was carved totaled
42,960,149 Mcf during 2001.

On September 4, 1996, the Trustee announced
a settlement of litigation filed by the Trustee against BROG and
Southland Royalty Company. In the settlement, agreement was
reached, among other things,

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regarding marketing arrangements for the sale of
those gas, oil and natural gas liquids products which are
subject to the Royalty (the Trust gas, oil and/or
natural gas liquids) as follows:




| |                                                                                                                                                                                                                                                                                                                                                              
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | (i) BROG agreed that, except for a
	pre-existing contract which has since expired, all subsequent
	contracts for the sale of Trust gas would require the written
	approval of an independent gas marketing consultant acceptable
	to the Trust;                                                                                                              
|
| | (ii) BROG will continue to market the Trust
	oil and natural gas liquids but will make payments to the Trust
	based on 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; and
|
| | (iii) The independent marketer of the Trust
	gas is entitled to use of BROGs current gas
	transportation, gathering, processing and treating agreements
	with third parties, at least through the remainder of their
	primary terms.                                                                                                                        

See Note 5 of Notes to Financial Statements
of the Trusts Annual Report to securityholders for the
year ended December 31, 2001 for further discussion of this
settlement and its impact on the Trust.

BROG entered into a contract dated
November 10, 1999, as amended, for the sale of all volumes
of Trust gas to Duke Energy and Marketing, L.L.C.
(Duke). That contract, as amended, provides for
delivery of gas at various delivery points over a period
commencing January 1, 2000 and ending March 31, 2002
and provides for the sale of Trust gas at prices which fluctuate
in accordance with published indices for gas sold in the
San Juan Basin of New Mexico. BROG has distributed requests
for proposal to 27 potential bidders with a view toward
selecting one or more contracts for the sale of Trust gas for
the period commencing April 1, 2002, through March 31,
2004.

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.

Oil and Gas Reserves

The following are definitions adopted by the
Securities and Exchange Commission (SEC) and the
Financial Accounting Standards Board which are applicable to
terms used within this Item:



| |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
| | -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | Estimated future net revenues are
	computed by applying current prices of oil and gas (with
	consideration of price changes only to the extent provided by
	contractual arrangements and allowed by federal regulation) to
	estimated future production of proved oil and gas reserves as of
	the date of the latest balance sheet presented, less estimated
	future expenditures (based on current costs) to be incurred in
	developing and producing the proved reserves, and assuming
	continuation of existing economic conditions. Estimated
	future net revenues are sometimes referred to in this
	Form 10-K as estimated future net cash flows.
|
| | Present value of estimated future net
	revenues is computed using the estimated future net
	revenues (as defined above) and a discount rate of 10%.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                        
|
| | Proved reserves are those estimated
	quantities of crude oil, natural gas and natural gas liquids,
	which, upon analysis of geological and engineering data, appear
	with reasonable certainty to be recoverable in the future from
	known oil and gas reservoirs under existing economic and
	operating conditions.                                                                                                                                                                                                                                                                                                                                       
|
| | Proved developed reserves are those
	proved reserves which can be expected to be recovered through
	existing wells with existing equipment and operating methods.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          
|
| | Proved undeveloped reserves are those
	proved reserves which are expected to be recovered from new
	wells on undrilled acreage, or from existing wells where a
	relatively major expenditure is required.                                                                                                                                                                                                                                                                                                                                                                                                                                                  

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The independent petroleum engineers reports
as to the proved oil and gas reserves as of December 31,
1999, 2000 and 2001 were prepared by Cawley,
Gillespie & Associates, Inc. The following table
presents a reconciliation of proved reserve quantities
attributable to the Royalty from December 31, 1998 to
December 31, 2001 (in thousands):

|                                            |  |           |      |             |  |  |          |  
|------------------------------------------- |  | --------- | ---- | ----------- |  |  | -------- | -
|                                            |  | Crude Oil |      | Natural Gas
|                                            |  | (Bbls)    |      | (Mcf)      
|                                            |  |           |      |            
|Reserves as of December 31, 1998            |  |           | 333  |             |  |  | 163,431  |  
|                                            |  |           |      |             |  |  |          |  
|Revisions of previous estimates             |  |           | 120  |             |  |  | 53,936   |  
|Extensions, discoveries and other additions |  |           | 29   |             |  |  | 14,498   |  
|Production                                  |  |           | (32  | )           |  |  | (17,650  | )
|                                            |  |           |      |             |  |  |          |  
|Reserves as of December 31, 1999            |  |           | 450  |             |  |  | 214,215  |  
|                                            |  |           |      |             |  |  |          |  
|Revisions of previous estimates             |  |           | 199  |             |  |  | 73,803   |  
|Extensions, discoveries and other additions |  |           | 80   |             |  |  | 36,207   |  
|Production                                  |  |           | (47  | )           |  |  | (20,318  | )
|                                            |  |           |      |             |  |  |          |  
|Reserves as of December 31, 2000            |  |           | 682  |             |  |  | 302,907  |  
|                                            |  |           |      |             |  |  |          |  
|Revisions of previous estimates             |  |           | (272 | )           |  |  | (116,270 | )
|Extensions, discoveries and other additions |  |           | 15   |             |  |  | 9,450    |  
|Production                                  |  |           | (42  | )           |  |  | (19,272  | )
|                                            |  |           |      |             |  |  |          |  
|Reserves as of December 31, 2001            |  |           | 383  |             |  |  | 176,815  |  
|                                            |  |           |      |             |  |  |          |  

Estimated quantities of proved developed reserves
of crude oil and natural gas as of December 31, 2001, 2000
and 1999 were as follows (in thousands):

|     |  |           |     |             |  |  |         | 
|---- |  | --------- | --- | ----------- |  |  | ------- | 
|     |  | Crude Oil |     | Natural Gas
|     |  | (Bbls)    |     | (Mcf)      
|     |  |           |     |            
|2001 |  |           | 356 |             |  |  | 162,577 | 
|2000 |  |           | 624 |             |  |  | 277,459 | 
|1999 |  |           | 422 |             |  |  | 201,891 | 

Generally, the calculation of oil and gas
reserves takes into account a comparison of the value of the oil
or gas to the cost of producing those minerals, in an attempt to
cause minerals in the ground to be included in reserve estimates
only to the extent that the anticipated costs of production will
be exceeded by the anticipated sales revenue. Accordingly, an
increase in sales price and/or a decrease in production cost can
itself result in an increase in estimated reserves and declining
prices and/or increasing costs can result in reserves reported
at less than the physical volumes actually thought to exist. The
Financial Accounting Standards Board requires supplemental
disclosures for oil and gas producers based on a standardized
measure of discounted future net cash flows relating to proved
oil and gas reserve quantities. Under this disclosure, future
cash inflows are estimated by applying year-end prices of oil
and gas relating to the enterprises proved reserves to the
year-end quantities of those reserves. Future price changes are
only considered to the extent provided by contractual
arrangements in existence at year-end. The standardized measure
of discounted future net cash flows is achieved by using a
discount rate of 10% a year to reflect the timing of future net
cash flows relating to proved oil and gas reserves.

Estimates of proved oil and gas reserves are by
their nature imprecise. Estimates of future net revenue
attributable to proved reserves are sensitive to the
unpredictable prices of oil and gas and other variables.
Accordingly, under the allocation method used to derive the
Trusts quantity of proved reserves, changes in prices will
result in changes in quantities of proved oil and gas reserves
and estimated future net revenues.

6



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##### Table of Contents



The 2001, 2000 and 1999 changes in the
standardized measure of discounted future net cash flows related
to future royalty income from proved reserves discounted at 10%
are as follows (in thousands):

|                                                               |  |      |          |      |  |      |         |   |  |   |         |  
|-------------------------------------------------------------- |  | ---- | -------- | ---- |  | ---- | ------- | - |  | - | ------- | -
|                                                               |  | 2001 |          | 2000 |  | 1999
|                                                               |  |      |          |      |  |     
|Balance, January 1                                             |  | $    | 818,212  |      |  | $    | 229,721 |   |  | $ | 144,472 |  
|Revisions of prior-year estimates, change in
	prices and other |  |      | (652,337 | )    |  |      | 530,811 |   |  |   | 90,172  |  
|Extensions, discoveries and other additions                    |  |      | 7,519    |      |  |      | 94,753  |   |  |   | 13,257  |  
|Accretion of discount                                          |  |      | 81,821   |      |  |      | 22,972  |   |  |   | 14,447  |  
|Royalty income                                                 |  |      | (81,369  | )    |  |      | (60,045 | ) |  |   | (32,627 | )
|                                                               |  |      |          |      |  |      |         |   |  |   |         |  
|Balance, December 31                                           |  | $    | 173,846  |      |  | $    | 818,212 |   |  | $ | 229,721 |  
|                                                               |  |      |          |      |  |      |         |   |  |   |         |  

Reserve quantities and revenues shown in the
tables above for the Royalty were estimated from projections of
reserves and revenues attributable to the combined BROG and
Trust interests. Reserve quantities attributable to the Royalty
were derived from estimates by allocating to the Royalty a
portion of the total net reserve quantities of the interests,
based upon gross revenue less production taxes. Because the
reserve quantities attributable to the Royalty are estimated
using an allocation of the reserves, any changes in prices or
costs will result in changes in the estimated reserve quantities
allocated to the Royalty. Therefore, the reserve quantities
estimated will vary if different future price and cost
assumptions occur. The future net cash flows were determined
without regard to future federal income tax credits available to
production from coal seam wells.

December average prices of $1.96 per Mcf of
conventional gas, $1.42 per Mcf of coal seam gas and
$15.79 per Bbl of oil were used at December 31, 2001,
in determining future net revenue. The downward revision in
reserve quantities for 2001 as compared to 2000 is primarily due
to significantly lower oil and gas prices in December 2001 as
compared to December 2000.

December average prices of $6.18 per Mcf of
conventional gas, $4.03 per Mcf of coal seam gas and
$24.67 per Bbl of oil were used at December 31, 2000,
in determining future net revenue. The upward revision in
reserve quantities for 2000 as compared to 1999 was primarily
due to significantly higher gas prices in December 2000.

December average prices of $2.39 per Mcf of
conventional gas, $1.49 per Mcf of coal seam gas and
$22.30 per Bbl of oil were used at December 31, 1999,
in determining future net revenue.

The following presents estimated future net
revenues and present value of estimated future net revenues
attributable to the Royalty for each of the years ended
December 31, 2001, 2000 and 1999 (in thousands except
amounts per Unit):

|                      |  |           |         |         |  |           |         |         |  |           |           |         |  |   |         |  |  |   |         |  |  |   |         | 
|--------------------- |  | --------- | ------- | ------- |  | --------- | ------- | ------- |  | --------- | --------- | ------- |  | - | ------- |  |  | - | ------- |  |  | - | ------- | 
|                      |  |           |         |         |  |          
|                      |  | 2001      |         | 2000    |  | 1999     
|                      |  |           |         |         |  |          
|                      |  | Estimated |         | Present |  | Estimated |         | Present |  | Estimated |           | Present
|                      |  | Future    |         | Value   |  | Future    |         | Value   |  | Future    |           | Value  
|                      |  | Net       |         | at      |  | Net       |         | at      |  | Net       |           | at     
|                      |  | Revenue   |         | 10%     |  | Revenue   |         | 10%     |  | Revenue   |           | 10%    
|                      |  |           |         |         |  |           |         |         |  |           |           |        
|Total Proved          |  | $         | 290,582 |         |  | $         | 173,846 |         |  | $         | 1,580,837 |         |  | $ | 818,212 |  |  | $ | 408,609 |  |  | $ | 229,721 | 
|Proved Developed      |  | $         | 266,834 |         |  | $         | 164,164 |         |  | $         | 1,445,557 |         |  | $ | 752,825 |  |  | $ | 383,356 |  |  | $ | 219,677 | 
|Total Proved Per Unit |  | $         | 6.23    |         |  | $         | 3.73    |         |  | $         | 33.92     |         |  | $ | 17.55   |  |  | $ | 8.77    |  |  | $ | 4.93    | 

Proved reserve quantities are estimates based on
information available at the time of preparation and such
estimates are subject to change as additional information
becomes available. The reserves actually recovered and the
timing of production of those reserves may be substantially
different from the above estimates. Moreover, the present values
shown above should not be considered as the market values of
such oil and gas reserves or the costs that would be incurred to
acquire equivalent reserves. A market value determination would
include many additional factors.

7



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##### Table of Contents



Regulation

Many aspects of the production, pricing and
marketing of crude oil and natural gas are regulated by federal
and state agencies. Legislation affecting the oil and gas
industry is under constant review for amendment or expansion,
frequently increasing the regulatory burden on affected members
of the industry.

Exploration and production operations are subject
to various types of regulation at the federal, state and local
levels. Such regulation includes requiring permits for the
drilling of wells, maintaining bonding requirements in order to
drill or operate wells, and regulating the location of wells,
the method of drilling and casing wells, the surface use and
restoration of properties upon which wells are drilled and the
plugging and abandonment of wells. Natural gas and oil
operations are also subject to various conservation laws and
regulations that regulate the size of drilling and spacing units
or proration units and the density of wells which may be drilled
and unitization or pooling of oil and gas properties. In
addition, state conservation laws establish maximum allowable
production from natural gas and oil wells, generally prohibit
the venting or flaring of natural gas and impose certain
requirements regarding the ratability of production. The effect
of these regulations is to limit the amounts of natural gas and
oil that BROG can produce and to limit the number of wells or
the locations at which BROG can drill.



| |                                
| | -------------------------------
| | Federal Natural Gas
	Regulation

The transportation and sale for resale of natural
gas in interstate commerce, historically, have been regulated
pursuant to several laws enacted by Congress and the regulations
promulgated under these laws by the Federal Energy Regulatory
Commission (FERC) and its predecessor. In the past,
the federal government has regulated the prices at which gas
could be sold. Congress removed all non-price controls affecting
wellhead sales of natural gas effective January 1, 1993.
Congress could, however, reenact price controls in the future.

Sales of natural gas are affected by the
availability, terms and cost of transportation. The price and
terms for access to pipeline transportation remain subject to
extensive federal and state regulation. Several major regulatory
changes have been implemented by Congress and FERC from 1985 to
the present that affect the economics of natural gas production,
transportation, and sales. In addition, FERC continues to
promulgate revisions to various aspects of the rules and
regulations affecting those segments of the natural gas
industry, most notably interstate natural gas transmission
companies, that remain subject to FERCs jurisdiction.
These initiatives may also affect the intrastate transportation
of gas under certain circumstances. The stated purpose of many
of these regulatory changes is to promote competition among the
various sectors of the natural gas industry and these
initiatives generally reflect more light-handed regulation of
the natural gas industry.

Additional proposals and proceedings that might
affect the natural gas industry are considered from time to time
by Congress, FERC, state regulatory bodies and the courts. The
Trust cannot predict when or if any such proposals might become
effective, or their effect, if any, on the Trust. The natural
gas industry historically has been very heavily regulated;
therefore, there is no assurance that the less stringent
regulatory approach pursued over the last decade by FERC and
Congress will continue.

The ability to transport and sell oil and natural
gas are dependent on pipelines whose rates, terms and conditions
of service are subject to FERC jurisdiction under the Interstate
Commerce Act. Certain regulations implemented by FERC in recent
years could result in an increase in the cost of transportation
service on certain petroleum products pipelines.



| |                      
| | ---------------------
| | Section 29 Tax Credit

The Trust began receiving royalty income from
coal seam gas wells in 1989. Under Section 29 of the
Internal Revenue Code, coal seam gas production from wells
drilled prior to January 1, 1993 (including certain wells
recompleted in coal seams formations thereafter), generally
qualifies for the federal income tax credit for producing
non-conventional fuels if such production and the sale thereof
occurs before January 1, 2003. For 2000, this tax credit
was $1.06 per MMBtu. For 2001, the amount of the credit
will be determined by the Treasury Department no later than
April 1, 2002, and, based on historical trends, is expected
to

8



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##### Table of Contents



approximate (within a 2-3% range) the 2000
credit. To benefit from the credit, each Unit holder must
determine from the tax information he receives from the Trust
his pro rata share of qualifying production of the Trust, based
upon the number of Units owned during each month of the year,
and the amount of available credit per MMbtu for the year, and
then apply the tax credit against his own income tax liability,
but such credit may not reduce his regular tax liability (after
the foreign tax credit and certain other nonrefundable credits)
below his tentative minimum tax. Section 29 also provides
that any amount of Section 29 credit disallowed for the tax
year solely because of this limitation will increase his credit
for prior year minimum tax liability, which may be carried
forward indefinitely as a credit against the taxpayers
regular tax liability, subject, however, to the limitations
described in the preceding sentence. There is no provision for
the carryback or carryforward of the Section 29 credit in
any other circumstances.


BROG provides the Trustee with certain
Section 29 tax credit information, including coal seam
volumes produced from Trust Properties. In 1999, the Tenth
Circuit Court upheld the position of the IRS and the Tax Court
that nonconventional fuel such as coal seam gas does not qualify
for the Section 29 credit unless the producer received a
formal certification from FERC. FERCs certification
authority expired effective January 1, 1993. However, on
July 14, 2000, FERC issued a final ruling amending its
regulations to reinstate certain regulations involving well
category determinations for all wells and tight formation areas
that could qualify for the Section 29 tax credit. BROG has
informed the Trustee that it will seek certification of all
qualified wells.



| |                 
| | ----------------
| | Other Regulation

The oil and natural gas industry is also subject
to compliance with various other federal, state and local
regulations and laws, including, but not limited to,
environmental protection, occupational safety, resource
conservation and equal employment opportunity.




Item 3.     Legal
Proceedings

Settlements

An administrative claim was initiated on
March 17, 1997 by the Mineral Management Service of the
United States Department of the Interior
(the MMS) against BROG regarding a gas contract
settlement dated March 1, 1990, between BROG and certain
other parties thereto. The claim alleges that additional
royalties are due on production from federal and Indian leases
in the State of New Mexico on properties that are burdened by
the Trust. On December 3, 2001, BROG settled this claim by
paying the Jicarilla Apache Nation the sum of $2,853,974 and the
MMS the sum of $1,224,043. MMS also retained certain
overpayments by BROG in the amount of $1,127,623 as part of the
settlement. Certain properties included in this settlement are
burdened by the Trust. BROG has indicated it will provide
information identifying the Underlying Properties affected by
the settlement, the Trusts share of the settlement, and
the manner and timing of deductions from upcoming
distribution(s) from the Trust. The Trusts legal and joint
interest auditing consultants will review the information to be
provided and advise the Trust as to the appropriateness of any
such deductions.

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

9



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##### Table of Contents



Administrative Proceedings

The following information was provided to the
Trust by BROG. Please note that the proceedings described below
apply to the collective interest of BROG and the Trust. BROG is
not able to estimate the amount of any potential loss to the
Trust in each of the outstanding proceedings, or the portion of
any such potential loss that would be allocated to the Royalty.

1.MMS Proceedings.

Blanco Pool.This
appeal arises from a MMS Demand Letter dated October 20,
1995, and bears MMS Appeal Docket No. MMS-95-0740. The
demand letter challenges the valuation benchmark
utilized by BROG for gas sold by BROG from the Blanco
Pool during the audit period of January 1, 1989
through December 31, 1991. BROG paid royalties on sales to
its marketing affiliate based on gross proceeds
received by BROG from its affiliate. The demand letter states
that BROG paid incorrectly under MMS regulations. The MMS
methodology in calculating the amounts demanded does not attempt
to trace resale proceeds. Instead, the auditors use published
index prices at pipeline interconnect points in the
San Juan Basin as a proxy for actual comparable sales, and
net out certain actual costs to move the gas to those index
points. While BROG had deducted prevailing field transportation
rates in computing its monthly prices in the San Juan
Basin, the auditors limited the deduction to the actual rate
paid to El Paso Natural Gas under a backhaul
agreement. The demand letter directs BROG to pay additional
royalties of $518,304, to recalculate royalties in accordance
with the MMS interpretation of the regulations and to pay
the difference between total royalty due and royalty paid.

Affiliate Proceeds Demand 
Conventional Gas.This appeal arises
from a MMS demand letter dated June 9, 1997, and bears MMS
Appeal Docket No. MMS-97-0168. The demand letter is a
blanket demand relating to all of BROGs non-coalbed
methane gas production nationwide for the audit period of
January 1, 1989 through December 31, 1994. The demand
letter is based primarily on the MMS theory that royalties are
to be based on BROGs marketing affiliate gross proceeds
rather than BROGs gross proceeds (e.g. the affiliate
resale proceeds issue). The demand letter directs BROG to
recalculate its royalties on these sales using a netback
calculation of the proceeds of the affiliate, and pay the
difference between total royalties due under such calculation
and the royalties actually paid by BROG. This demand letter is
in furtherance of the demand letter described in the prior
paragraph.

Coalbed Methane.This appeal arises from a MMS demand letter dated
October 28, 1996, and bears MMS Appeal Docket
No. MMS-96-0437. The demand letter relates to BROGs
coalbed methane production from the Northeast Blanco Unit for
the audit period of May 1, 1990 through December 31,
1993, and from the San Juan 30-6 Unit for the audit period
of January 1, 1989 through December 31, 1991. Like the
Blanco Pool demand letter, the demand letter does not attempt to
trace resale proceeds. The issues are whether MMS should bear
its share of CO2 extraction costs and, if so, whether
the costs should be based on market rates or actual costs of the
system, and whether MMS share of transportation costs
(which MMS does not dispute it must bear) should be based on
market rates or actual costs of the system. BROG is directed to
pay additional royalties of $3,600,584 for underpayment of
royalty for gas produced from the units mentioned above, to
recalculate royalties for gas produced from other federal leases
in accordance with MMS interpretation of the regulations
and to pay the difference between total royalty due and royalty
paid.

Due to the similarity of the claims in the Blanco
Pool, Affiliate Proceeds Demand and the Coal Bed Methane
administrative appeals, to the claims in the suits in the In re
Natural Gas Royalties qui tam litigation described below, the
administrative appeals have been stayed by agreement with MMS
pending the resolution of the gas qui tam litigation, and
settlement discussions between BROG and the federal government
in the gas qui tam litigation will, if successful, include the
settlement of each of the MMS Proceedings.

2.Jicarilla Indian Tribe Proceedings.

This appeal arises from a MMS Order to Perform
dated June 10, 1998. The Order to Perform states that, in
valuing production for royalty purposes, BROG must perform
(i) a major portion analysis (i.e., calculate value on the
highest price paid or offered for a major portion of the gas
produced from the field where the leased lands are situated) and
(ii) a dual accounting calculation (i.e., compute royalties
on the greater of the

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##### Table of Contents



value of gas prior to processing or the combined
value of processed residue gas and plant products plus the value
of any condensate recovered downstream without processing). BROG
currently performs dual accounting calculations on Indian
leases, but the Order alleges that its dual accounting
calculations are based on less than major portion prices. BROG
believes that producers do not have access to prices received by
other producers in a field, so a major portion calculation must
be done by MMS.


In December 2000, BROG and the Tribe entered into
a settlement resolving the issues associated with the dual
accounting calculation. The total settlement amount was
$3,260,366. BROG is currently determining what portion of this
dual accounting settlement will be allocated to the Trust. Any
such allocation will be reviewed by the Trusts
consultants. The major portion calculation issue remains
outstanding.

Litigation

1.Grynberg Litigation.

In September 1998, BROG was advised by the United
States Department of Justice under an order of confidentiality
that a lawsuit styled United States of America ex rel
Jack J. Grynberg v. Burlington Resources
Oil & Gas, et al, Civil Action No. 97-CV-189
and 190, United States District Court for the District of
Wyoming, had been filed under seal pursuant to the qui tam
provisions of the civil federal False Claims Act, and that
seventy-seven similar cases had been filed by the plaintiff
against other companies. The complaint alleges that BROG engaged
in the mismeasurement of volumes and wrongful analysis of
heating content of natural gas and engaged in other activities,
including the sale of natural gas to affiliated companies, which
resulted in the underpayment of royalties to the United States.
The government investigated the plaintiffs claims, and in
May 1999 issued notice that the United States would not
intervene in the case. The lawsuits have been unsealed by the
court and the plaintiff has served the complaint on BROG. This
claim was subsequently consolidated into a multi-district
litigation proceeding as described in paragraph 2 below.

2. In re Natural Gas Royalties
Qui Tam Litigation.

On March 28, 2000, the United States
District Court for the Eastern District of Texas, Lufkin
Division, ordered that the first amended complaint in the case
of United States ex rel. M. Glenn
Osterhoudt, III v. Amerada Hess, et al. Civil
Action No. 9:98CV101, in the United States District Court
for the Eastern District of Texas, Lufkin Division, and the
second amended complaint in the case of United States of America
ex rel. Harrold E. (Gene) Wright v Agip Petroleum
Burlington, et al. Civil Action No. C-5:96CV243 be
unsealed and served upon defendants, including BROG. In these
lawsuits, the plaintiffs have alleged violations of the civil
False Claims Act. Plaintiffs contend that defendants underpaid
royalties on natural gas and natural gas liquids produced on
federal and Indian lands through the use of below-market prices,
improper deductions, improper measurement techniques and
transactions with affiliated companies. The United States has
filed an intervention in these cases as to some of the
defendants, including BROG.

In July 2000, the United States District Court
for the District of New Mexico unsealed and BROG was served
with the petition in United States of America ex rel.
Mark A. Perry v. BROG Resources, Inc., et al,
Civil Action No. 9:00CV197, in the United States District
Court for the District of New Mexico, wherein plaintiff
alleges violations of the civil False Claims Act. The plaintiff
claims that BROG understated the value of natural gas and
natural gas liquids produced on federal and Indian lands in
connection with its computation and reporting of royalty
payments. The United States has elected to intervene in this
case, but a complaint has not been served upon BROG.

In October 2000, the federal Judicial Panel on
Multidistrict Litigation ordered that the Wright and Osterhoudt
lawsuits be transferred to the United States District Court for
the District of Wyoming for inclusion with the Grynberg lawsuit
described in paragraph 1 above in multidistrict litigation
proceedings. A similar order was issued in December 2000
transferring the Perry lawsuit. These cases have been
consolidated for pre-trial proceedings in the matter styled
In re Natural Gas Royalties Qui Tam Litigation,
MDL-1293, United States District Court for the District of
Wyoming.

If successful, this litigation could result in a
decrease in royalty income received by the Trust. At this time,
no estimate can be made as to the amount of any potential loss
in this litigation, or the portion of any

11



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such potential loss that would be allocated to
the Trusts interest. Any proposed allocation of loss to
the Trust will be reviewed by the Trusts consultants.


3. Quinque Litigation.

In September 1999, BROG was served with a class
action petition styled Quinque Operating Burlington on behalf of
Gas Producers v. Gas Pipelines, et al., Case
No. 99 C 30, In the District Court of Stevens
County, Kansas, naming certain of its current or former
affiliates as defendants, along with hundreds of other gas
production and gas pipeline companies. The petition alleges that
the defendants engaged in the mismeasurement of volumes and
wrongful analysis of heating content of natural gas and engaged
in other activities which resulted in the underpayment of
revenue owed to working interest owners, royalty interest
owners, overriding royalty interest owners and state taxing
authorities. If successful, this litigation could result in a
decrease in royalty income received by the Trust. At this time,
no estimate can be made as to the amount of any loss in this
litigation, or the portion of any such potential loss that would
be allocated to the Trust. Any proposed allocation of loss to
the Trust will be reviewed by the Trusts consultants.




Item 4.     Submission
of Matters to a Vote of Security Holders

No matters were submitted to a vote of Unit
holders, through the solicitation of proxies or otherwise,
during the fourth quarter ended December 31, 2001.




PART II




Item 5.     Market
for Units of the Trust and Related Security Holder
Matters

The information under Units of Beneficial
Interest at page 1 of the Trusts Annual Report
to security holders for the year ended December 31, 2001,
is herein incorporated by reference.




Item 6.     Selected
Financial Data

|                              |  |                                |            |      |  |      |            |      |  |      |            |  |  |   |            |  |  |   |            | 
|----------------------------- |  | ------------------------------ | ---------- | ---- |  | ---- | ---------- | ---- |  | ---- | ---------- |  |  | - | ---------- |  |  | - | ---------- | 
|                              |  |                               
|                              |  | For the Year Ended December 31
|                              |  |                               
|                              |  | 2001                           |            | 2000 |  | 1999 |            | 1998 |  | 1997
|                              |  |                                |            |      |  |      |            |      |  |     
|Royalty income                |  | $                              | 81,368,723 |      |  | $    | 60,044,773 |      |  | $    | 32,626,966 |  |  | $ | 30,317,860 |  |  | $ | 49,497,479 | 
|Distributable income          |  |                                | 80,126,202 |      |  |      | 59,188,932 |      |  |      | 31,795,667 |  |  |   | 29,498,402 |  |  |   | 48,648,930 | 
|Distributable income per Unit |  |                                | 1.719123   |      |  |      | 1.269909   |      |  |      | 0.682182   |  |  |   | 0.635039   |  |  |   | 1.043770   | 
|Distributions per Unit        |  |                                | 1.719123   |      |  |      | 1.269909   |      |  |      | 0.682182   |  |  |   | 0.635039   |  |  |   | 1.043770   | 
|Total assets, December 31     |  |                                | 38,051,369 |      |  |      | 47,659,746 |      |  |      | 49,048,652 |  |  |   | 53,753,582 |  |  |   | 61,231,280 | 




Item 7.     Managements
Discussion and Analysis of Financial Condition and Results of
Operation

The Trustees Discussion and
Analysis and Results of the 4th Quarters of
2001 and 2000 at pages 7 through 9 of the
Trusts Annual Report to securityholders for the year ended
December 31, 2001, are herein incorporated by reference.




Item 7A.     Quantitative
and Qualitative Disclosure About Market Risk

The Trust has not entered into derivative
financial instruments, derivative commodity instruments or other
similar instruments during 2001. As discussed in Item 2.
Properties  Pricing Information, the Trust does not
market the Trust gas, oil and/or natural gas liquids. BROG is
responsible for such marketing.




Item 8.     Financial
Statements and Supplementary Data

The Financial Statements of the Trust and the
notes thereto at page 10 et seq., of the Trusts
Annual Report to security holders for the year ended
December 31, 2001, are herein incorporated by reference.

12



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##### Table of Contents






Item 9.     Changes
in and Disagreements with Accountants on Accounting and
Financial Disclosure

See information contained in the Trusts
Form 8-K dated July 17, 2001 reporting change in
accountants.




PART III




Item 10.     Directors
and Executive Officers of the Registrant

The Trust has no directors or executive officers.
The Trustee is a corporate trustee which may be removed, with or
without cause, at a meeting of the Unit holders, by the
affirmative vote of the holders of a majority of all the Units
then outstanding.




Item 11.     Executive
Compensation

The Trust has no directors or executive officers.
During the year ended December 31, 2001, the Trustee
received total remuneration as follows:

|                                                 |  |               |         |              |  |   |            |    
|------------------------------------------------ |  | ------------- | ------- | ------------ |  | - | ---------- | ---
|                                                 |  | Capacities in |         | Cash        
|Name of Individual or Number of Persons in Group |  | Which Served  |         | Compensation
|                                                 |  |               |         |             
|Bank One, N.A.                                   |  |               | Trustee |              |  | $ | 125,259.37 | (1)



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                             
|--- | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | Under the Trust Indenture, the Trustee is
	entitled to an administrative fee for its administrative
	services, preparation of quarterly and annual statements with
	attention to tax and legal matters of: (i) 1/20 of 1% of
	the first $100 million of the annual gross revenue of the
	Trust, and 1/30 of 1% of the annual gross revenue of the Trust
	in excess of $100 million and (ii) the Trustees
	standard hourly rates for time in excess of 300 hours
	annually. The administrative fee is subject to reduction by a
	credit for funds provision.




Item
12.     Security Ownership of
Certain Beneficial Owners and Management

(a) Security Ownership of Certain
Beneficial Owners. The following table sets forth, as of
December 31, 2001, information with respect to each person
known to own beneficially more than 5% of the outstanding Units
of the Trust:

|                                          |                                |                         |                  |                  |  |  |       |  | 
|----------------------------------------- | ------------------------------ | ----------------------- | ---------------- | ---------------- |  |  | ----- |  | 
|                                          |                                | Amount and Nature       |                  |                 
|Name and Address                          |                                | of Beneficial Ownership |                  | Percent of Class
|                                          |                                |                         |                  |                 
|Alpine Capital, L.P.(1)                   |                                |                         | 12,585,900 Units |                  |  |  | 27.0% | 
|                                          | 201 Main Street, Suite 3100    |                         |                  |                  |  |  |       |  | 
|                                          | Fort Worth, Texas 76102        |                         |                  |                  |  |  |       |  | 
|Societe General Asset Management Corp.(2) |                                |                         | 5,180,000 Units  |                  |  |  | 11.1% | 
|                                          | 1221 Avenue of the Americas    |                         |                  |                  |  |  |       |  | 
|                                          | New York, New York 10020       |                         |                  |                  |  |  |       |  | 
|McMorgan and Company(3)                   |                                |                         | 3,000,000 Units  |                  |  |  | 6.4%  | 
|                                          | 1 Bush Street, Suite 800       |                         |                  |                  |  |  |       |  | 
|                                          | San Francisco, CA 94104        |                         |                  |                  |  |  |       |  | 
|Capital Group International, Inc.(4)      |                                |                         | 2,400,000 Units  |                  |  |  | 5.2%  | 
|                                          | Capital Guardian Trust Company |                         |                  |                  |  |  |       |  | 
|                                          | 11100 Santa Monica Blvd.       |                         |                  |                  |  |  |       |  | 
|                                          | Los Angeles, CA 90025          |                         |                  |                  |  |  |       |  | 



---



|    |                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(1) | This information was provided to the Trust on
	Amendment Number 24 to Schedule 13D, dated
	March 15, 2002, as filed with the Securities and Exchange
	Commission (SEC) by Alpine Capital, L.P.
	(Alpine), which indicated that these Units were
	beneficially owned by Alpine. Robert W. Bruce, III and
	Algenpar, Inc., are general partners of Alpine and have shared
	power to vote and dispose of the Units held by Alpine. The
	Amendment Number 24 to Schedule 13D may be reviewed
	for more detailed information concerning the matters summarized
	herein.

13



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##### Table of Contents





|    |                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|(2) | This information was provided to the Trust on
	Amendment Number 3 to Schedule 13G, dated
	January 6, 1999, as filed with the SEC. The Amendment
	Number 3 to Schedule 13G may be reviewed for more
	detailed information concerning the matters summarized herein.                                                                                                                                                        
|   
|(3) | This information was provided to the Trust in a
	Schedule 13G dated July 12, 1999, as filed with the
	SEC. The Schedule 13G may be reviewed for more detailed
	information concerning the matters summarized herein.                                                                                                                                                                                                      
|   
|(4) | This information was provided to the Trust in
	Amendment Number 4 to Schedule 13G dated
	December 31, 2001. Capital Group International, Inc. and
	Capital Guardian Trust Company each reported sole voting power
	over 1,853,600 Units and sole dispositive power over
	2,400,000 Units. The Amendment Number 4 to
	Schedule 13G may be reviewed for more detailed information
	concerning the matters summarized herein.

(b) Security Ownership of Management.
In various fiduciary capacities, Bank One, N.A. owned, as of
December 31, 2001, an aggregate of 37,252 Units with
no right to vote any of these Units. Bank One, N.A. disclaims
any beneficial interest in these Units. The number of Units
reflected in this paragraph includes Units held by all branches
of Bank One, N.A.




Item
13.     Certain Relationships and
Related Transactions

The Trust has no directors or executive officers.
See Item 11 for the remuneration received by the Trustee
during the year ended December 31, 2001 and Item 12(b)
for information concerning Units owned by Bank One, N.A. in
various fiduciary capacities.




PART IV




Item 14.     Exhibits,
Financial Statement Schedules and Reports On
Form 8-K

The following documents are filed as a part of
this Report:

Financial Statements

Included in Part II of this Report by
reference to the Annual Report of the Trust for the year ended
December 31, 2001:



| |                                                   
| | --------------------------------------------------
| | Independent Auditors Reports                     
| | Statements of Assets, Liabilities and Trust Corpus
| | Statements of Distributable Income                
| | Statements of Changes in Trust Corpus             
| | Notes to Financial Statements                     

Financial Statement Schedules

Financial statement schedules are omitted because
of the absence of conditions under which they are required or
because the required information is given in the financial
statements or notes thereto.

14



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##### Table of Contents



Exhibits

|        |        |  |  |                    |  |                                                                                                                                                                                                                                                                                                                                                               
|------- | ------ |  |  | ------------------ |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |        |  |  |                   
|Number  |        |  |  | Number Description
|        |        |  |  |                   
|        | (4)(a) |  |  |                   |  | San Juan Basin Royalty Trust Indenture,
	dated November 3, 1980, between Southland Royalty Company
	and The Fort Worth National Bank (now Bank One, N.A.), as
	Trustee, heretofore filed as Exhibit 4(a) to the
	Trusts Annual Report on Form 10-K to the SEC for the
	fiscal year ended December 31, 1980, is incorporated herein
	by reference.*           
|        | (b)    |  |  |                   |  | Net Overriding Royalty Conveyance from Southland
	Royalty Company to the Forth Worth National Bank (now Bank One,
	N.A.), as Trustee, dated November 3, 1980 (without
	Schedules), heretofore filed as Exhibit 4(b) to the
	Trusts Annual Report on Form 10-K to the SEC for the
	fiscal year ended December 31, 1980, is incorporated herein
	by reference.*
|        | (13)   |  |  |                   |  | Registrants Annual Report to security
	holders for fiscal year ended December 31, 2001.**                                                                                                                                                                                                                                                                    
|        | (23.1) |  |  |                   |  | Consent of Cawley, Gillespie &
	Associates, Inc., reservoir engineer.**                                                                                                                                                                                                                                                                                       



---



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

Reports on Form 8-K

None.

15



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##### Table of Contents






SIGNATURE

Pursuant to the Requirements of Section 13
or 15(d) of the Securities Exchange Act of 1934, the Registrant
has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.



| |                                            
| | -------------------------------------------
| | BANK ONE, N.A.                             
| | TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST
|
| | /s/ LEE ANN ANDERSON                       
| |                                            
| | Lee Ann Anderson                           
| | Vice President                             

Date: April 1, 2002

(The Trust has no directors or executive officers)

16



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##### Table of Contents






EXHIBIT INDEX

|        |        |  |  |                    |  |                                                                                                                                                                                                                                                                                                                                                               
|------- | ------ |  |  | ------------------ |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Exhibit |        |  |  |                   
|Number  |        |  |  | Number Description
|        |        |  |  |                   
|        | (4)(a) |  |  |                   |  | San Juan Basin Royalty Trust Indenture,
	dated November 3, 1980, between Southland Royalty Company
	and The Fort Worth National Bank (now Bank One, N.A.), as
	Trustee, heretofore filed as Exhibit 4(a) to the
	Trusts Annual Report on Form 10-K to the SEC for the
	fiscal year ended December 31, 1980, is incorporated herein
	by reference.*           
|        | (b)    |  |  |                   |  | Net Overriding Royalty Conveyance from Southland
	Royalty Company to the Forth Worth National Bank (now Bank One,
	N.A.), as Trustee, dated November 3, 1980 (without
	Schedules), heretofore filed as Exhibit 4(b) to the
	Trusts Annual Report on Form 10-K to the SEC for the
	fiscal year ended December 31, 1980, is incorporated herein
	by reference.*
|        | (13)   |  |  |                   |  | Registrants Annual Report to security
	holders for fiscal year ended December 31, 2001.**                                                                                                                                                                                                                                                                    
|        | (23.1) |  |  |                   |  | Consent of Cawley, Gillespie &
	Associates, Inc., reservoir engineer.**                                                                                                                                                                                                                                                                                       



---



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