10-K

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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, 2005
	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 Amended and Restated San Juan Basin Royalty Trust Indenture)

Texas	75-6279898
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
TexasBank, Trust Department 2525 Ridgmar Boulevard, Suite 100 Fort Worth, Texas	76116 (Zip Code)
(Address of principal executive offices)

(866) 809-4553
(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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act).  Yes þ     No o

Large Accelerated filer þ     Accelerated filer o     Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ

State the aggregate market value of the Units of Beneficial Interest held by non-affiliates of the Registrant as of June 30, 2005: $1,955,155,092.

At March 6, 2006, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

“Units of Beneficial Interest” at page 1; “Description of the Properties” at page 4; “Trustee’s Discussion and Analysis” at pages 5-10; and “Statements of Assets, Liabilities and Trust Corpus,” “Statements of Distributable Income,” “Statements of Changes in Trust Corpus,” “Notes to Financial Statements,” and “Report of Independent Registered Public Accounting Firm” at page 12 et seq., in registrant’s Annual Report to Unit Holders for the year ended December 31, 2005, are incorporated herein by reference for Item 5 (Market for Registrant’s Units, Related Security Holder Matters and Issuer Purchases of Units), Item 7 (Trustee’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.

TABLE OF CONTENTS

PART I
	ITEM 1. BUSINESS
	ITEM 1A. RISK FACTORS
	ITEM 1B. UNRESOLVED STAFF COMMENTS
	ITEM 2. PROPERTIES
	ITEM 3. LEGAL PROCEEDINGS
	ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
PART II
	ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS
	ITEM 6. SELECTED FINANCIAL DATA
	ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
	ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
	ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
	ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
	ITEM 9A. CONTROLS AND PROCEDURES
	ITEM 9B. OTHER INFORMATION
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 AND RELATED SECURITY HOLDER MATTERS
	ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
	ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
	ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
SIGNATURE
Annual Report to Unit Holders
Consent of Cawley, Gillespie & Associates, Inc.
Certification Required by Rule 13a-14(a)
Certification Required by Rule 13a-14(b)

PART I

Certain information included in this Annual Report on Form 10-K contains, and other materials filed or to be filed by the San Juan Basin Royalty Trust (the “Trust”) with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices, estimated future net revenues, estimates of reserves, the results of the Trust’s activities, and regulatory matters. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements reflect Burlington Resources Oil & Gas Company LP’s (“BROG”), the working interest owner’s current view with respect to future events; are based on an assessment of, and are subject to, a variety of factors deemed relevant by TexasBank, the Trustee of the Trust, and BROG and involve risks and uncertainties. These risks and uncertainties include volatility of oil and gas prices, product supply and demand, competition, regulation or government action, litigation and uncertainties about estimates of reserves. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated.

ITEM 1.   BUSINESS

The Trust is an express trust created under the laws of the state of Texas by the San Juan Basin Royalty Trust Indenture (the “Original Indenture”) entered into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and The Fort Worth National Bank. Effective as of September 30, 2002, the Original Indenture was amended and restated (the Original Indenture, as amended and restated, the “Indenture”). The Trustee of the Trust is TexasBank. The principal office of the Trust is located at 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116, Attention: Trust Department (telephone number (866) 809-4553). The Trust maintains a website at www.sjbrt.com. The Trust makes available (free of charge) its annual, quarterly and current reports (and any amendments thereto) filed with the Securities and Exchange Commission (the “SEC”) through its website as soon as reasonably practicable after electronically filing or furnishing such material with or to the SEC.

On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company’s conveyance of a 75% 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 (the “Royalty”) carved out of that company’s oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of northwestern New Mexico. Pursuant to the Net Overriding Royalty Conveyance (the “Conveyance”) the Royalty was transferred to the Trust on November 3, 1980, effective as to production from and after November 1, 1980 at 7:00 a.m.

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 was carved out of and now burdens the Underlying Properties as more particularly described under “Item 2. Properties” herein.

The Royalty constitutes the principal asset of the Trust. 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

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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 freely tradeable Unit for each share of the common stock of Southland Royalty then held. Holders of Units are referred to herein as “Unit Holders.” Subsequent to the Conveyance of the Royalty, through a series of assignments and mergers, Southland Royalty’s successor became BROG.

The function of the 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. The Trust is not empowered to carry on any business activity and has no employees. All administrative functions are performed by the Trustee.

The Trust received approximately $153.8 million, $111.0 million and $92.0 million in Royalty Income from BROG in each of the fiscal years ended December 31, 2005, 2004 and 2003, respectively. After deducting administrative expenses and accounting for interest income and any change in cash reserves, the Trust distributed approximately $151.6 million, $109.0 million and $90.0 million to Unit Holders in each of the fiscal years ended December 31, 2005, 2004 and 2003, respectively. The Trust’s corpus was approximately $23.9 million, $26.7 million and $29.8 million as of December 31, 2005, 2004 and 2003, respectively.

The term “net proceeds,” as used in the 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 Underlying Properties) from the sale of the production attributable to the Underlying Properties subject to certain adjustments. “Production costs” generally means costs incurred on an accrual basis by BROG in operating the Underlying Properties, 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 the Underlying Properties 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 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.

Compliance with state and federal environmental protection laws could reduce the Royalty Income received by the Trust. Costs of complying with such laws and regulations affect the production costs incurred by BROG in operating the Underlying Properties and may also affect capital expenditures by BROG. The Trust has no information regarding any estimated capital expenditures by BROG specifically allocable to environmental control facilities in the current or succeeding fiscal years.

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 an 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.

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. Unit Holders of record as of the last business day of each month (the “monthly record date”) will be entitled to receive the calculated monthly distribution amount for such month on or before ten business days after the monthly record date. The amount of each monthly distribution will generally be determined and announced ten days before the monthly record date. The aggregate monthly distribution amount is the excess of (i) the net proceeds attributable to the Royalty paid to the Trustee, 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.

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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, certificates of deposit of banks having capital, surplus and undivided profits in excess of $50,000,000, or money market funds that have been rated AAAmg or AAAm by Standard & Poor’s and AA by Moody’s, 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 Royalty Income 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.

The exploration for and the production of gas and oil is a speculative business. The Trust has no means of ensuring continued income from the Royalty at the present level or otherwise. In addition, fluctuations in prices and supplies of gas and oil and the effect these fluctuations might have on royalty income to the Trust and on reserves net to the Trust cannot be accurately projected. The Trustee has no information with which to make any projections beyond information on economic conditions that is generally available to the public and thus is unwilling to make any such projections.

BROG has the right to sell its interest in the Underlying Properties and has recommended to the Trust that certain Underlying Properties BROG believes are marginal be sold to third parties. BROG has asked the Trust to join in the proposed sale by conveying the Royalty burdening those properties. The properties BROG currently proposes to sell constitute less than 2% of the value of the Royalty. The Trustee is currently evaluating whether its joinder in the sale would be in the best interest of the Unit Holders. Any such sale would require Unit Holder approval of an amendment to the Indenture that would allow the Trustee to sell up to a specified percentage of the value of the Royalty each year without obtaining the consent of Unit Holders.

ITEM 1A.   RISK FACTORS

Although risk factors are described elsewhere in this Annual Report on Form 10-K, the following is a summary of the principal risks associated with an investment in Units in the Trust.

Oil and gas prices fluctuate due to a number of factors, and lower prices will reduce net proceeds to the Trust and distributions to Unit Holders.

The Trust’s monthly distributions are highly dependent upon the prices realized from the sale of gas and, to a lesser extent, oil. Oil and gas prices can fluctuate widely on a month-to-month basis in response to a variety of factors that are beyond the control of the Trust and BROG. Factors that contribute to price fluctuation include, among others:

•  political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;

•  worldwide economic conditions;

•  weather conditions;

•  the supply and price of foreign oil and gas;

•  the level of consumer demand;

•  the price and availability of alternative fuels;

•  the proximity to, and capacity of, transportation facilities; and

•  the effect of worldwide energy conservation measures.

Moreover, government regulations, such as regulation of natural gas transportation and price controls, can affect product prices in the long term.

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Lower oil and gas prices may reduce the amount of oil and gas that is economic to produce and reduce net profits to the Trust. The volatility of energy prices reduces the predictability of future cash distributions to Unit Holders.

Increased costs of production and development will result in decreased Trust distributions.

Production and development costs attributable to the Underlying Properties are deducted in the calculation of net proceeds. Accordingly, higher or lower production and development costs, without concurrent increases in revenues, directly decrease or increase the share of net proceeds paid to the Trust as Royalty Income.

If development and production costs of the Underlying Properties exceed the proceeds of production from the Underlying Properties, such excess costs are carried forward and the Trust will not receive a share of net proceeds for the Underlying Properties until future net proceeds from production from such properties exceed the total of the excess costs. Development activities may not generate sufficient additional revenue to repay the costs; however, the Trust is not obligated to repay the excess costs except through future production.

Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future revenues to be too high.

The value of the Units of the Trust depends upon, among other things, the amount of reserves attributable to the Royalty and the estimated future value of the reserves. Estimating reserves is inherently uncertain. Ultimately, actual production, revenues and expenditures for the Underlying Properties will vary from estimates and those variations could be material. Petroleum engineers consider many factors and make assumptions in estimating reserves. Those factors and assumptions include:

•  historical production from the area compared with production rates from similar producing areas;

•  the assumed effect of governmental regulation; and

•  assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures.

Changes in these assumptions can materially change reserve estimates. The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.

The operators of the Underlying Properties are subject to extensive governmental regulation.

Oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations.

Operating risks for BROG and other operators of the Underlying Properties can adversely affect Trust distributions.

Royalty Income payable to the Trust is derived from the production and sale of oil and gas, which operations are subject to risk inherent in such activities, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks and litigation concerning routine and extraordinary business activities and events. These risks could result in substantial losses which are deducted in calculating the net proceeds paid to the Trust due to injury and loss of life, severe damage to and destruction of property and equipment, pollution and other environmental damage and suspension of operations.

None of the Trustee, the Trust nor the Unit Holders control the operation or development of the Underlying Properties.

Neither the Trustee nor the Unit Holders can influence or control the operation or future development of the Underlying Properties. The Underlying Properties are owned by BROG and BROG operates the majority of such

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properties and handles the calculation of the net proceeds attributable to the Royalty and the payment of Royalty Income to the Trust.

The Royalty can be sold and the Trust can be terminated in certain circumstances.

The Trust will be terminated and the Trustee must sell the Royalty if holders of at least 75% of the Units approve the sale or vote to terminate the Trust, or if the Trust’s gross revenue for each of two successive years is less than $1,000,000 per year. Following any such termination and liquidation, the net proceeds of any sale will be distributed to the Unit Holders and Unit Holders will receive no further distributions from the Trust. We cannot assure you that any such sale will be on terms acceptable to all Unit Holders.

Mineral properties, such as the Underlying Properties are depleting assets and, if BROG or other operators of the Underlying Properties do not perform additional development projects, the assets may deplete faster than expected.

The Royalty Income payable to the Trust is derived from the sale of depleting assets. Accordingly, the portion of the distributions to Unit Holders (to the extent of depletion taken) may be considered a return of capital. The reduction in proved reserve quantities is a common measure of depletion. Future maintenance and development projects on the Underlying Properties will affect the quantity of proved reserves. The timing and size of these projects will depend on the market prices of natural gas. If BROG does not implement additional maintenance and development projects, the future rate of production decline of proved reserves may be higher than the rate currently expected by the Trust.

Unit Holders have limited voting rights.

Voting rights as a Unit Holder are more limited than those of stockholders of most public corporations. For example, there is no requirement for annual meetings of Unit Holders or for an annual or other periodic re-election of the Trustee. Unlike corporations which are generally governed by boards of directors elected by their equity holders, the Trust is administered by a corporate Trustee in accordance with the Indenture and other organizational documents. The Trustee has extremely limited discretion in its administration of the Trust.

ITEM 1B.   UNRESOLVED STAFF COMMENTS

The Trust has not received any written comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934 that remain unresolved.

ITEM 2.   PROPERTIES

The Royalty conveyed to the Trust was carved out of Southland Royalty’s (now BROG’s) working interests and royalty interests in certain properties situated in the San Juan Basin in northwestern New Mexico. See “Item 1. Business” for information on the conveyance of the Royalty to the Trust. 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 this Item 2 is based upon data and information furnished to the Trustee by BROG.

Producing Acreage, Wells and Drilling

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 in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico and 4,429 gross (1,277 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.

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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.

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. A payadd is the completion of an additional productive interval in an existing completed zone in a well.

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 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 the Royalty Income payable to the Trust, 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.

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 ten 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 and a reduction of its program for infill drilling in the Fruitland Coal formation.

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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 density in the Fruitland Coal formation. Eighty-acre density 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.

Oil and Gas Production

The Trust recognizes production during the month in which the related net proceeds attributable to the Royalty are paid to the Trust. 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. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2005, were as follows:

	2005				2004				2003
	Gas		Oil		Gas		Oil		Gas		Oil
	(Mcf)		(Bbls)		(Mcf)		(Bbls)		(Mcf)		(Bbls)
Production		26,600,644		43,142		25,324,435		44,832		25,922,650		43,123
Average Price	$	6.27	$	49.62	$	4.68	$	34.81	$	3.93	$	26.11

Pricing Information

Gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. Gas production from the Underlying Properties totaled 42,867,162 Mcf during 2005.

On September 4, 1996, the Trustee announced a settlement of litigation filed by the Trustee against BROG (the “1996 Settlement”). In the 1996 Settlement, agreement was reached, among other things, regarding marketing arrangements for the sale of those gas, oil and natural gas liquids products from the Underlying Properties going forward as follows:

(i) BROG agreed that all subsequent contracts for the sale of gas from the Underlying Properties would require the written approval of an independent gas marketing consultant acceptable to the Trust;

(ii) BROG will continue to market the oil and natural gas liquids from the Underlying Properties but will make payments to the Trust based on actual proceeds from such sales, and 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 gas from the Underlying Properties 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.

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 twelve 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 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 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

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Resources, L.P., respectively, (ii) the delivery of such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until terminated by either party on twelve months notice, and (iii) the sale of such gas at prices which fluctuate in accordance with the published indices for gas sold in the San Juan Basin of 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 twelve 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, 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.

Oil and Gas Reserves

The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Annual Report on Form 10-K:

“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 Annual Report on 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, 2003, 2004 and 2005, were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2002, to December 31, 2005, (in thousands):

	Crude			Natural
	Oil			Gas
	(Bbls)			(Mcf)
Reserves as of December 31, 2002		448			235,466
Revisions of previous estimates		(31	)		17,045
Extensions, discoveries and other additions		8			14,021
Production		(43	)		(25,923	)
Reserves as of December 31, 2003		382			240,609
Revisions of previous estimates		102			26,415
Extensions, discoveries and other additions		20			15,236
Production		(45	)		(25,324	)
Reserves as of December 31, 2004		459			256,936
Revisions of previous estimates		15			14,401
Extensions, discoveries and other additions		23			17,023
Production		(43	)		(26,601	)
Reserves as of December 31, 2005		454			261,759

Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2005, 2004 and 2003 were as follows (in thousands):

	2005		2004		2003
Crude Oil (Bbls)		395		419		349
Natural Gas (Mcf)		231,235		235,272		218,266

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, less estimated future expenditures (based on current costs) of developing and producing the proved reserves, and assuming continuation of existing economic conditions. 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.

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The 2005, 2004 and 2003 changes in the standardized measure of discounted future net cash flows related to future royalty income from proved reserves are as follows (in thousands):

	2005			2004			2003
Balance, January 1	$	756,017		$	497,701		$	411,882
Revisions of prior-year estimates, change in prices and other		339,865			272,251			106,935
Extensions, discoveries and other additions		72,698			47,338			29,693
Accretion of discount		75,602			49,770			41,188
Royalty Income		(153,858	)		(111,043	)		(91,997	)
Balance, December 31	$	1,090,324		$	756,017		$	497,701

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 $9.04 per Mcf of conventional gas, $7.05 per Mcf of coal seam gas and $54.17 per Bbl of oil were used at December 31, 2005, in determining future net revenue. The upward revision in reserve quantities for 2005 as compared to 2004 is due in part to higher oil and gas prices in December 2005 as compared to December 2004.

December average prices of $6.33 per Mcf of conventional gas, $4.82 per Mcf of coal seam gas and $38.79 per Bbl of oil were used at December 31, 2004, in determining future net revenue. The upward revision in reserve quantities for 2004 as compared to 2003 was due in part to higher oil and gas prices in December 2004 as compared to December 2003.

December average prices of $4.47 per Mcf of conventional gas, $3.31 per Mcf of coal seam gas and $28.12 per Bbl of oil were used at December 31, 2003, 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, 2005, 2004 and 2003 (in thousands, except amounts per Unit):

	2005				2004				2003
	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	$	2,018,722	$	1,090,324	$	1,382,108	$	756,017	$	899,477	$	497,701
Proved Developed	$	1,785,597	$	965,615	$	1,264,556	$	696,430	$	818,782	$	458,224
Total Proved Per Unit	$	43.31	$	23.39	$	29.65	$	16.22	$	19.30	$	10.68

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 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 require the analysis of additional parameters.

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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.

Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products 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

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

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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.

Passive Loss Rules

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.

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

As discussed herein under Part II, Item 9A (Controls and Procedures), due to the pass-through nature of the Trust, BROG provides much of the information disclosed in this Form 10-K and the other periodic reports filed by the Trust with the SEC. Although the Trustee receives periodic updates from BROG regarding activities which may relate to the Trust, the Trust’s ability to timely report certain information required to be disclosed in the Trust’s periodic reports is dependent on BROG’s timely delivery of the information to the Trust.

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.

In addition to the litigation described above, BROG is involved in various legal proceedings, the outcome of which may impact the Trust. Should certain legal proceedings to which BROG is a party be decided in a manner adverse to BROG, the amount of Royalty Income received by the Trust could materially decrease. The Trust has not received from BROG any estimate of the amount of any potential loss in such proceedings, or the portion of any such potential loss that might be allocated to the Royalty.

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, 2005.

PART II

ITEM 5.   MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS

The information under “Units of Beneficial Interest” at page 1 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2005, is herein incorporated by reference. The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

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ITEM 6.   SELECTED FINANCIAL DATA

	2005		2004		2003		2002		2001
Royalty Income	$	153,858,264	$	111,042,767	$	91,997,262	$	38,053,281	$	81,368,723
Distributable income		151,560,081		109,390,735		90,357,837		36,417,967		80,126,202
Distributable income per Unit		3.251747		2.346998		1.938644		0.781354		1.719123
Distributions per Unit		3.251747		2.346998		1.938644		0.781354		1.719123
Total assets, December 31		43,054,656		36,814,866		36,905,104		37,972,696		38,051,369

ITEM 7.   TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

The “Description of the Properties” and “Trustee’s Discussion and Analysis” at pages 5 through 10 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2005, are herein incorporated by reference.

ITEM 7A.   QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The Trust invests in no derivative financial instruments, and has no foreign operations or long-term debt instruments. The Trust is a passive entity and is prohibited from engaging in any business or commercial activity of any kind whatsoever, including borrowing transactions, other than the Trust’s ability to borrow money periodically as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unit Holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit Holders to any foreign currency related market risk. The Trust does not market the gas, oil and/or natural gas liquids from the Underlying Properties. 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 12 et seq., of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2005, are herein incorporated by reference.

ITEM 9.   CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Within the two most recent fiscal years, there have been no changes in and disagreements with the Trust’s independent accountants.

ITEM 9A.   CONTROLS AND PROCEDURES

The Trust maintains a system of disclosure controls and procedures that is designed to ensure that information required to be disclosed in the Trust’s filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by BROG to the Trustee and its employees who participate in the preparation of the Trust’s periodic reports to allow timely decisions regarding disclosure. Due to the pass-through nature of the Trust, BROG provides much of the information disclosed in this Form 10-K and the other periodic reports filed by the Trust with the SEC.

The Indenture does not require BROG to update or provide information to the Trust. Under the Conveyance transferring the Royalty to the Trust, BROG is obligated to provide the Trust with certain information concerning calculations of net proceeds owed to the Trust, among other information. Pursuant to the 1996 Settlement, BROG

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agreed to new, more formal financial reporting and audit procedures as compared to those provided in the Conveyance.

The Trustee receives periodic updates from BROG regarding activities related to the Trust. Accordingly, the Trust’s ability to timely report certain information required to be disclosed in the Trust’s periodic reports is dependent on BROG’s timely delivery of such information to the Trust. In order to help ensure the accuracy and completeness of the information required to be disclosed in the Trust’s periodic reports, the Trust employs independent public accountants, joint interest auditors, marketing consultants, attorneys and petroleum engineers. These outside professionals advise the Trustee in its review and compilation of this information for inclusion in this Form 10-K and the other periodic reports provided by the Trust to the SEC.

The Trustee has evaluated the Trust’s disclosure controls and procedures as of December 31, 2005, and has concluded that such disclosure controls and procedures are effective at the “reasonable assurance” level to ensure that material information related to the Trust is gathered on a timely basis to be included in the Trust’s periodic reports. In reaching its conclusion, the Trustee considered the Trust’s dependence on BROG to deliver timely and accurate information to the Trust. The Trustee has not reviewed the Trust’s disclosure controls and procedures in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee.

During the quarter ended December 31, 2005, there were no changes in the Trust’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) that materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee has not evaluated the Trust’s internal control over financial reporting in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee.

Trustee’s Report on Internal Control Over Financial Reporting

TexasBank, in its capacity as trustee (the “Trustee”) of San Juan Basin Royalty Trust (the “Trust”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.

As of December 31, 2005, the Trustee assessed the effectiveness of the Trust’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control — Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, the Trustee determined that the Trust maintained effective internal control over financial reporting as of December 31, 2005, based on those criteria.

Weaver and Tidwell, L.L.P., the independent registered public accounting firm that audited the financial statements of the Trust included in this Annual Report on Form 10-K, has issued an attestation report on the Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005. The report, which expresses unqualified opinions on the Trustee’s assessment and on the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting”.

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Report of Independent Registered Public
Accounting Firm on Internal Control Over Financial Reporting

We have audited the assessment of TexasBank (the “Trustee”), included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting, that San Juan Basin Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.

We conducted our audit 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 effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the trust’s modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles. A trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with its modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Trustee’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2005, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the COSO criteria.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus 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 of the Trust and our report dated March 10, 2006 expressed an unqualified opinion thereon.

/s/  Weaver and Tidwell, L.L.P.

Weaver and Tidwell, L.L.P.

Fort Worth, Texas

March 10, 2006

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ITEM 9B.   OTHER INFORMATION

All information required to be disclosed by the Trust in a Current Report on Form 8-K during the fourth quarter of the year ended December 31, 2005, has previously been reported on a Form 8-K.

PART III

ITEM 10.   DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The Trust has no directors, executive officers or employees; the Trust is managed by a corporate trustee. Accordingly, the Trust does not have an audit committee, audit committee financial expert or a code of ethics applicable to executive officers. The Trustee, however, has adopted a policy regarding standards of conduct and conflicts of interest applicable to all directors, officers and employees of the Trustee. 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.

Section 16(a) Beneficial Ownership Reporting Compliance

The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions which occurred in 2005.

ITEM 11.   EXECUTIVE COMPENSATION

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not have a compensation committee or maintain any equity compensation plans, and there are no Units reserved for issuance under any such plans.

During the past three years the Trustee received total remuneration as follows:

			Capacities in		Cash
Name of Individual or Entity	Year		Which Served		Compensation(1)
TexasBank		2005		Trustee	$	310,461
TexasBank		2004		Trustee	$	259,472
TexasBank		2003		Trustee	$	234,064

(1) Under the Indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates for time in excess of 300 hours annually. 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).

ITEM 12.   SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS

The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.

(a) Security Ownership of Certain Beneficial Owners.  As of March 6, 2006, no person was known to beneficially own more than 5% of the outstanding Units of the Trust.

(b) Security Ownership of Trustee.  As of March 6, 2006, TexasBank beneficially owned 2,380 Units, or less than one percent of the Units. TexasBank has sole voting and dispository power over all of these Units.

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ITEM 13.   CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The Trust has no directors or executive officers and is not empowered to carry on any business activity. Accordingly, there are no relationships or related transactions to which the Trust was a party that are required to be disclosed. See Item 11 for the remuneration received by the Trustee during the year ended December 31, 2005 and Item 12 for information concerning Units owned by the Trustee.

ITEM 14.   PRINCIPAL ACCOUNTANT FEES AND SERVICES

The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P., the Trust’s principal accountants, for the audit of the Trust’s annual financial statements for the fiscal years ended December 31, 2005 and 2004 and fees billed for other services rendered to the Trust by Weaver and Tidwell, L.L.P. during those periods.

	2005		2004
Audit Fees	$	76,065	$	34,760
Audit-Related Fees		-0-		−0-
Tax Fees		8,085		8,690
All Other Fees		-0-		−0-
Total	$	84,150	$	43,450

Audit Fees consist of fees billed for professional services rendered for the audit of the Trust’s annual financial statements and internal control over financial reporting, review of the interim financial statements included in the Trust’s quarterly reports and services that are normally provided by Weaver and Tidwell, L.L.P. in connection with statutory and regulatory filings or engagements.

Audit-Related Fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements. This category includes fees related to audit and attest services not required by statute or regulations and consultations concerning financial accounting and reporting standards.

Tax Fees consist of fees for professional services billed for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance, return preparation, preparation of the B-schedules and tax booklet.

All Other Fees consist of fees billed for products and services other than the services reported above.

The Trust has no directors or executive officers. Accordingly, the Trust does not have an audit committee and there are no audit committee pre-approval policies or procedures relating to services provided by the Trust’s independent accountants. Pursuant to the terms of the Indenture, the Trustee engages and approves all services rendered by the Trust’s independent accountants.

17

PART IV

ITEM 15.   EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

The following documents are filed as a part of this Annual Report on Form 10-K:

Financial Statements

Included in Part II of this Annual Report on Form 10-K by reference to the Trust’s Annual Report to Unit Holders for the year ended December 31, 2005:

Report of Independent Registered Public Accounting Firm

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.

Exhibits

Exhibit
Number		Description
	4(a)	Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.*
	4(b)	Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
	4(c)	Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.*
	10	Indemnification Agreement, dated May 13, 2003, with effectiveness as of July 30, 2002, by and between Lee Ann Anderson and San Juan Basin Royalty Trust, heretofore filed as Exhibit 10(a) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2003, is incorporated herein by reference.
	13	Registrant’s Annual Report to Unit Holders for the fiscal year ended December 31, 2005.**
	23	Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
	31	Certification required by Rule 13a-14(a), dated March 15, 2006, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee for the Trust.**
	32	Certification required by Rule 13a-14(b), dated March 15, 2006, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank on behalf of TexasBank, the Trustee of the Trust.***

*	A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
**	Filed herewith.
***	Furnished herewith.

18

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.

SAN JUAN BASIN ROYALTY TRUST

By:  TEXASBANK, AS TRUSTEE OF THE

SAN JUAN BASIN ROYALTY TRUST

By:  /s/  Lee Ann Anderson

Lee Ann Anderson

Vice President and Trust Officer

Date: March 15, 2006

(The Trust has no directors or executive officers)

19

EXHIBIT INDEX

Exhibit
Number		Description
	4(a)	Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.*
	4(b)	Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
	4(c)	Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.*
	10	Indemnification Agreement, dated May 13, 2003, with effectiveness as of July 30, 2002, by and between Lee Ann Anderson and San Juan Basin Royalty Trust, heretofore filed as Exhibit 10(a) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2003, is incorporated herein by reference.
	13	Registrant’s Annual Report to Unit Holders for the fiscal year ended December 31, 2005.**
	23	Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
	31	Certification required by Rule 13a-14(a), dated March 15, 2006, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee for the Trust.**
	32	Certification required by Rule 13a-14(b), dated March 15, 2006, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the Trust.***

*	A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
**	Filed herewith.
***	Furnished herewith.

20

EX-13

EXHIBIT 13

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

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.

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.

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

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.

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.

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.

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

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

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

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.

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.

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

The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. As of September 30, 2002, TexasBank (“Trustee”) replaced Bank One, N.A., as Trustee for the Trust. Southland Royalty Company (“Southland”)

conveyed to the Trust a 75% net overriding royalty interest (“Royalty”) carved out of Southland’s working interests and royalty interests (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.

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

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

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 Framework issued 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

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

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.

EX-23

EXHIBIT 23

[Cawley, Gillespie & Associates, Inc., letterhead]

March 15, 2006

San Juan Basin Royalty Trust
TexasBank, Trust Department
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas 76116

Ladies and Gentlemen:

     Cawley, Gillespie & Associates, Inc. hereby consents to the use of the oil and gas reserve information in the San Juan Basin Royalty Trust Securities & Exchange Commission Form 10-K for the year ended December 31, 2005 and in the San Juan Basin Royalty Trust Annual Report for the year ended December 31, 2005 based on reserve reports prepared by Cawley, Gillespie & Associates, Inc. and dated March 15, 2006.

Sincerely,

     /s/ Cawley, Gillespie & Associates, Inc.

CAWLEY, GILLESPIE & ASSOCIATES, INC.

EX-31

Exhibit 31

CERTIFICATION

I, Lee Ann Anderson, certify that:

     1. I have reviewed this Annual Report on Form 10-K of San Juan Basin Royalty Trust, for which TexasBank acts as Trustee;

     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report;

     4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

     5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal control over financial reporting.

     In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Burlington Resources Oil & Gas Company LP.

Date: March 15, 2006	By:	/s/ Lee Ann Anderson
		Lee Ann Anderson
		Vice President and Trust Officer, TexasBank

EX-32

Exhibit 32

CERTIFICATION OF
THE TRUSTEE*
OF THE SAN JUAN BASIN ROYALTY TRUST
PURSUANT TO 18 U.S.C. § 1350

     In connection with the accompanying report on Form 10-K for the year ended December 31, 2005, and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the San Juan Basin Royalty Trust (the “Trust”), not in its individual capacity but solely as Trustee of the Trust, hereby certify that:

1.

The Report fully complies in all material respects with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (as explained in Note 3 to the Trust’s financial statements contained in the Trust’s Annual Report to Unit Holders for the year ended December 31, 2005, attached as Exhibit 13 to the Report, in accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 47, released September 16, 1982, the Trust prepares its financial statements in a manner that differs from generally accepted accounting principles; such presentation is customary to other royalty trusts); and

2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.

TEXASBANK, AS TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST
By:	/s/ Lee Ann Anderson
Name:	Lee Ann Anderson
Title:	Vice President and Trust Officer
Date:	March 15, 2006

* The Trust has no executive officers.