exv13

Exhibit 13

San Juan Basin Royalty Trust 2006 ANNUAL REPORT & and Form 10 — K &

No 1

The Trust

THE PRINCIPAL ASSET of the San Juan Basin Royalty Trust (the “Trust”) consists of a 75% net overriding royalty interest (the “Royalty”) carved out of certain oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of northwestern New Mexico.

Units of Beneficial interest

The units of beneficial interest of the Trust (the “Units”) are traded on the New York Stock Exchange under the symbol “SJT.” At February 26, 2007, the closing price of a Unit was $31.98. From January 1, 2005, to December 31, 2006, the quarterly high and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows:


					DISTRIBUTIONS
	HIGH		LOW		PAID

2006

First Quarter	$	45.9900	$	36.0000	$	1.083276
Second Quarter		43.7500		33.0000		.599299
Third Quarter		41.2500		32.8200		.666989
Fourth Quarter		39.0000		32.6200		.565491

TOTAL FOR 2006					$	2.915055


2005
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

TOTAL FOR 2005					$	3.251747

At February 16, 2007, there were 46,608,796 Units outstanding held by 1,709 Unit holders of record. The following table presents information relating to the distribution of record ownership of Units:


	NUMBER OF
type of unit holders	UNIT HOLDERS		UNITS HELD

Individuals, Joint Holders and Minors		1,504		1,888,965
Fiduciaries		162		495,464
Government Bodies		1		30
Clubs, Associations or Societies		7		13,120
Depositary (for all beneficial holders)		1		43,864,558
Corporations		34		346,659

TOTAL		1,709		46,608,796

No 2

To Unit Holders

WE ARE PLEASED TO PRESENT THE 2006 ANNUAL REPORT of the San Juan Basin Royalty Trust. The report includes a copy of the Trust’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “Commission”) for the year ended December 31, 2006, 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”). On March 31, 2006, a subsidiary of ConocoPhillips completed its acquisition of Burlington Resources, Inc., BROG’s parent. As a result, ConocoPhillips became the parent of Burlington Resources, Inc., which in turn, is the parent of BROG. The Trust was established in November 1980 by Southland. Pursuant to the Indenture that governs the operations of the Trust, Southland 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.

The Royalty constitutes the principal asset of the Trust. Under the Indenture governing the Trust, the function of Compass Bank, 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 2006 was $135,867,325 or $2.915055 per Unit. Distributable Income (as hereinafter defined) for 2006 consisted of Royalty Income of $136,311,892 plus interest income of $1,207,360, less administrative expenses of $1,651,927. Information about the Trust’s estimated proved reserves of gas, including coal seam gas, and of oil as well as the present value of net revenues discounted at 10% can be found in Item 2 of the accompanying Form 10-K. 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, 2007, and for the year ending December 31, 2007. Unit holders owning Units in nominee name may obtain monthly tax information from the Trust’s Web site or 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. (GRAPHICS)


Compass Bank, Trustee
By:		Lee Ann Anderson Vice President and Senior Trust Officer

No 3

No 4

Description of the Properties

The principal asset of the Trust is a 75% net overriding royalty interest (the “Royalty”) carved out of certain working, royalty and other 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 4,616 gross (1,286 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, 2006, 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.

In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division (the “OCD”) had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In July 2003, the OCD approved 160-acre spacing in the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.

The Federal Energy Regulatory Commission is primarily responsible for federal regulation of natural gas. For a further discussion of gas pricing, gas purchasers, gas production and regulatory matters affecting gas production see Item 2, “Properties,” in the accompanying Form 10-K.

Trustee’s Discussion and Analysis

Gas and Oil Production

Total gas and oil production from the Underlying Properties for the five years ended December 31, 2006, were as follows:


	2006		2005		2004		2003		2002

Gas — Mcf		40,900,570		42,867,162		44,015,816		45,202,576		46,206,297
Mcf per Day		112,056		117,444		120,262		123,843		126,593
Oil — Bbls		74,438		69,558		77,341		74,727		93,659
Bbls per Day		204		191		211		205		257

No 5

Trustee’s Discussion and Analysis

Gas and Oil Production cont.

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:


	2006		2005		2004		2003		2002

Gas — Mcf		22,475,405		26,600,644		25,324,435		25,922,650		19,584,056
Average Price (per Mcf)	$	6.55	$	6.27	$	4.68	$	3.93	$	2.32
Oil — Bbls		40,702		43,142		44,832		43,123		40,215
Average Price (per Bbl)	$	61.30	$	49.62	$	34.81	$	26.11	$	20.90

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. These contracts provided for (i) the sale of such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services (“PNM”), 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 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. (“ChevronTexaco”), and Coral Energy Resources, L.P. (“Coral”), 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 New Mexico. With respect to BROG’s contract with PNM, BROG and PNM entered into a letter agreement dated January 31, 2005, pursuant to which the parties waived 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. Neither BROG nor any of ChevronTexaco, Coral nor PNM gave notice to terminate the three contracts described above for the sale of all volumes of gas produced from the Underlying Properties and, accordingly, the terms of those contracts have been extended through March 31, 2008.

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.

No 6

Trustee’s Discussion and Analysis

Royalty Income

Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income for the five years ended December 31, 2006, was determined as shown in the following table:


	2006			2005			2004			2003			2002

Gross Proceeds from the Underlying Properties

Gas	$	264,428,021		$	267,895,460		$	204,682,365		$	175,653,183		$	103,349,299
Oil		4,561,342			3,451,115			2,670,763			1,938,972			1,863,827
Other		1,384,848	¹		2,405,486	²		3,314,808	³		(1,202,368	)⁴		(5,110,589	)⁵

TOTAL	$	270,374,211		$	273,752,061		$	210,667,936		$	176,389,787		$	100,102,537


Less Production Costs

Capital Expenditures	$	39,195,168		$	19,127,698		$	22,338,684		$	20,590,704		$	21,470,777
Severance Tax — Gas		25,652,907			26,717,315			19,766,231			17,281,986			9,752,508
Severance Tax — Oil		460,702			362,023			253,022			174,750			151,594
Other		42,968			273,766			42,763			41,850			18,037
Lease Operating Expenses and Property Taxes		23,273,276			22,126,907			20,210,213			15,637,481			15,701,740

TOTAL	$	88,625,021		$	68,607,709		$	62,610,913		$	53,726,771		$	47,094,656


Excess Production Costs
Interest on Excess		-0-			-0-			-0-			-0-			(2,259,628	)⁶
Production Costs		-0-			-0-			-0-			-0-			(10,545	)⁶
Net Profits	$	181,749,190		$	205,144,352		$	148,057,023		$	122,663,016		$	50,737,708
Net Overriding
Royalty Interest		75	%		75	%		75	%		75	%		75	%
Royalty Income	$	136,311,892		$	153,858,264		$	111,042,767		$	91,997,262		$	38,053,281


⁽¹⁾		Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions, and a portion of the arbitration award issued November 11, 2005 in favor of the Trust.


⁽²⁾		Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions.

⁽³⁾		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 bus ness interruption claim.

⁽⁴⁾		Represents a settlement between BROG and the Mineral Management Service of the United States Department of the Interior (the “MMS”).

⁽⁵⁾		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.

⁽⁶⁾		RePresents excess production costs incurred in December 2001 and recovered by BROG in 2002, plus interest.

Distributable Income

“Distributable Income” (as that term is used herein) 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, 2006, Distributable Income was $135,867,325, representing a 10% decrease from 2005. For the year ended December 31, 2005, Distributable Income was $151,560,081, representing a 38% increase from 2004. Distributable Income in 2004 was $109,390,735.

The Trust received Royalty Income of $136,311,892 and interest income of $1,207,360 in 2006. After deducting administrative expenses of $1,651,927, Distributable Income for 2006 was $135,867,325 ($2.915055 per Unit). In 2005, Royalty Income was $153,858,264, interest income was $167,367, and administrative expenses were $2,465,550, resulting in Distributable Income of $151,560,081 ($3.251747 per Unit). Although the average gas price increased from $6.25 per Mcf for 2005 to $6.47 per Mcf for 2006, the 10% decrease in Distributable Income from 2005 to 2006 was primarily attributable to an approximately $20 million increase in capital expenditures in 2006 as compared to 2005. Interest earnings in 2006 were higher, as compared to 2005, primarily due to additional interest received in July as partial payment of the Arbitration Award described in

No 7

Trustee’s Discussion and Analysis

Note 7 to the financial statements included herewith. Administrative expenses were lower in 2006, as compared to 2005. Higher expenses were incurred in 2005 primarily as a result of compliance with the new internal control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002, costs incurred in resolving certain outstanding audit issues and obtaining the Arbitration Award.

In 2004, the Trust received Royalty Income of $111,042,767 and interest income of $58,885. After deducting administrative expenses of $1,710,917, Distributable Income for 2004 was $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 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, costs incurred in resolving certain outstanding audit issues and obtaining the Arbitration Award.

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.

Operating Expenses

Monthly operating expenses of the Underlying Properties, exclusive of property taxes, in 2006 averaged approximately $1,871,974, which is higher than the $1,769,538 average in 2005 and higher than the $1,639,670 average in 2004. Operating expenses have increased primarily because increased activity strained the capacity of service vendors and resulted in increasing costs.

Settlements

As part of the September 4, 1996, settlement of the litigation filed by the Trustee on June 4, 1992 against BROG and Southland, 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 or credits received from BROG totaling approximately $21,600,000.

Capital Expenditures

During 2006, in calculating Royalty Income, BROG deducted $39.2 million of capital expenditures for projects, including drilling and completion of 115 gross (24.14 net) conventional wells, two gross (0.003 net) payadds, two gross (1.74 net) recompletions, three gross (2.50 net) restimulations, 44 gross (14.63 net) coal seam wells, seven gross (0.28 net) coal seam payadds, two gross (0.48 net) coal seam recompletions, and two gross (0.08 net) coal seam miscellaneous capital projects.

There were 100 gross (26.27 net) conventional wells, 14 gross (0.39 net) payadds, seven gross (3.49 net) recompletions, six gross (4.02 net) restimulations, four gross (0.02 net) miscellaneous capital projects, 28 gross (11.79 net) coal seam wells, one gross (0.04 net) coal seam payadd, five gross (3.57 net) coal seam recompletions, and two gross (0.004 net) coal seam restimulations in progress as of December 31, 2006.

The aggregate capital expenditures reported by BROG in calculating Royalty Income for 2006 include approximately

No 8

Trustee’s Discussion and Analysis

$12.2 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 $24.8 million for 2006 budgeted projects were used in calculating net proceeds payable to the Trust in calendar year 2006, and approximately $7.1 million in capital expenditures from the 2006 budget were used in calculating net proceeds payable to the Trust for January and February 2007. Therefore, an additional approximately $5.7 million in capital expenditures for budgeted 2006 projects remains to be spent.

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 (o.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. 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.

BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2007 is estimated at $28 million. Approximately $24 million of that budget is allocable to 112 new wells, including 33 wells scheduled to be dually completed in the Mesaverde and Dakota formations and 10 wells scheduled to be dually completed in the Fruitland Coal and Pictured Cliffs formations. BROG indicates that 34 of the new wells, at an aggregate cost of approximately $11.4 million, are projected to be drilled to formations producing coal seam gas. BROG reports that based on its actual capital requirements, the pace of regulatory approvals, the mix of projects and swings in the price of natural gas, the actual capital expenditures for 2007 could range from $20 million to $50 million.

Contractual Obligations

Under the Indenture governing the Trust, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates (currently ranging from $75.00 to $250.00 per hour) 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).

Effects of Securities Regulation

As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is and will continue to be subject to extensive regulation under, among others, the Securities Act of 1933, the Securities Exchange Act of 1934 (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.

No 9

Trustee’s Discussion and Analysis

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.

Critical Accounting Policies

In accordance with the Commission’s staff accounting bulletins and consistent with other royalty trusts, the financial statements of the Trust are prepared on the following basis:

•		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.

No 10

Trustee’s Discussion and Analysis

Results of the 4^TH Ruarters of 2006 & 2005

For the three months ended December 31, 2006, Distributable Income was $26,356,915 ($.565491 per Unit), which was less than the $46,012,856 ($.987214 per Unit) of income distributed during the same period in 2005. The decrease in Distributable Income resulted primarily from lower average gas 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, 2006 and 2005 were as follows:


	2006		2005

Underlying Properties

Gas — Mcf		9,782,562		10,248,571
Mcf per Day		106,332		111,398
Average Price (per Mcf)	$	5.49	$	7.77
Oil — Bbls		14,992		16,477
Bbls per Day		163		179
Average Price (per Bbl)	$	60.72	$	59.06

Attributable to the Royalty

Gas — Mcf		5,156,724		6,516,096
Oil — Bbls		7,794		10,429

The average price of gas decreased and the average price of oil increased in 2006 compared to the prior year. The price per barrel of oil during the fourth quarter of 2006 was $1.66 per Bbl higher than that received in the fourth quarter of 2005 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 2006 failed to completely offset the natural decline in production from existing wells. In addition, production volumes were reduced in 2006 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 2006 totaled $8,436,427 compared to $4,734,866 during the same period of 2005. Lease operating expenses and property taxes for the fourth quarter of 2006 averaged $1,819,291 per month compared to $1,939,447 per month in the fourth quarter of 2005. Operating expenses were lower in the fourth quarter of 2006 than for the fourth quarter of 2005 primarily because in calculating Royalty Income for December 2006, BROG included a deduction of $583,725 from lease operating expense as a result of the granting of certain audit exceptions for the period 2003-2005.

Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarter of 2006 and 2005 were as follows:


	2006		2005

October	$	.257200	$	.243762
November		.210820		.334553
December		.097471		.408899

QUARTER TOTAL	$	.565491	$	.987214

No 11

San Juan Basin Royalty Trust

Statements of Assets, Liabilities and Trust Corpus

December 31, 2006 and 2005


	2006		2005

Assets
Cash and Short-Term Investments	$	4,657,886	$	19,173,162
Net Overriding Royalty Interests in Producing Oil and gas Properties — Net		21,823,390		23,881,494

TOTAL	$	26,481,276	$	43,054,656


	2006		2005

Liabilities and Trust Corpus
Distribution Payable to Unit holders	$	4,543,028	$	19,058,304
Cash Reserves		114,858		114,858
Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding		21,823,390		23,881,494

TOTAL	$	26,481,276	$	43,054,656

Statements of Distributable Income

For the three years ended December 31, 2006


	2006		2005		2004

Royalty Income	$	136,311,892	$	153,858,264	$	111,042,767
Interest Income		1,207,360		167,367		58,885

		137,519,252		154,025,631		111,101,652

Expenditures — General and Administrative		1,651,927		2,465,550		1,710,917
Distributable Income	$	135,867,325	$	151,560,081	$	109,390,735

Distributable Income per Unit (46,608,796 Units)	$	2.915055	$	3.251747	$	2.346998

Statements of Changes in Trust Corpus

For the three years ended December 31 ,2006


	2006			2005			2004

Trust Corpus, Beginning of Period	$	23,881,494		$	26,674,821		$	29,822,820
Amortization of Net Overriding Royalty Interest		(2,058,104	)		(2,793,327	)		(3,147,999	)
Distributable Income		135,867,325			151,560,081			109,390,735
Distributions Declared		(135,867,325	)		(151,560,081	)		(109,390,735	)

Trust Corpus, End of Period	$	21,823,390		$	23,881,494		$	26,674,821

These financial statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.

No 13

Notes to Financial Statements

1. Trust Organization And Provisions

The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. 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 of northwestern New Mexico. Through an acquisition completed March 24, 2006, Compass Bank succeeded TexasBank as “Trustee” (herein so called) of the Trust. On February 16, 2007, Compass Bancshares, Inc. announced the signing of a definitive agreement to be acquired by Banco Bilbao Vizcaya Argentaria, S.A (“BBVA”). Under the terms of that agreement, Compass Bancshares, Inc. would become a wholly-owned subsidiary of BBVA. The transaction is expected to close in the second half of 2007 and is subject to the approval of shareholders of BBVA and Compass Bancshares, Inc. as well as to regulatory approval and customary closing conditions.

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. Net Overriding Royalty Interest And Distribution To Unit Holders

The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are determined on a monthly basis by the Trustee. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalty, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month and such negative amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or before 10 business days after the monthly record date, which is generally the last business day of each calendar month.

The cash received by the Trustee consists of the proceeds received by the owner of the Underlying Properties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75%.

The initial carrying value of the Royalty ($133,275,528) represented Southland’s historical net book value at the date of the transfer of the Trust. Accumulated amortization as of December 31, 2006 and 2005 aggregated $111,452,138 and $109,394,034, respectively.

3. Basis Of Accounting

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

No 14

Notes to financial Statements

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 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. Federal Income Taxes

For federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit holders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.

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 certain coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits under Section 29 (now Section 45K) of the Internal Revenue Code of 1986, as amended (the “Code”), through 2002, but not thereafter. Accordingly, under present law, the Trust’s production and sale of gas from coal seam wells does not qualify for tax credit under Section 45K of the Code (the “Section 45K Tax Credit”). Congress has at various times since 2002 considered energy legislation, including provisions to reinstate the Section 45K Tax 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. For example, on August 8, 2005, new energy tax legislation was enacted which, among other things, modified the Section 45K Tax Credit in several respects, but did not extend the credit for production from coal seam wells. No prediction can be made as to what future tax legislation affecting Section 45K of the Code, 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. Certain Contracts

BROG previously entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties. These contracts provided for (i) the sale of such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services (“PNM”), 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 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. (“ChevronTexaco”), and Coral Energy Resources, L.P. (“Coral”), 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 New Mexico. With respect to BROG’s contract with PNM, BROG and PNM 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

No 15

Notes to financial Statements

other. Neither BROG nor any of ChevronTexaco, Coral nor PNM gave notice to terminate the three contracts described above for the sale of all volumes of gas produced from the Underlying Properties, and, accordingly, the terms of those contracts have been extended through March 31, 2008.

6. Significant Customers

Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is 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. Settlements and Litigation

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.

During 2006, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, an aggregate of $1,981,933 was included in calculating net proceeds paid to the Trust, together with interest of $1,124,063 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 alleged 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 sought to recover its attorneys’ fees. The Trust filed an answer and counterclaim in the litigation filed by BROG denying those allegations and asking that the arbitrator’s award be confirmed. On April 20, 2006, the Court entered an Order denying BROG’s motion to vacate and granting the Trust’s application to confirm the Arbitration Award and on June 6, 2006, rendered a final judgment in favor of the Trust. However, on May 22, 2006, BROG filed a Notice of Appeal indicating its desire to appeal the Order and any final judgment confirming the Arbitration Award and on July 5, 2006, filed a Motion for New Trial in the District Court of Harris County, Texas, urging substantially similar arguments made at the hearing. The Trust responded to the Motion for New Trial and served BROG with post-judgment discovery requests. BROG’s Motion for New Trial was overruled on August 4, 2006. BROG’s distribution to the Trust for July 2006 included $1,534,182 representing a portion of the Arbitration Award, plus accrued interest. Of this amount, $1,325,826 (the equivalent of $994,270 grossed up to account for the Trust’s 75% net overriding royalty interest) was included in calculating the net proceeds paid to the Trust, and the accrued interest thereon was $539,812. The balance of the Arbitration Award is pending BROG’s appeal, which has been assigned No. 01-06-00485-CV in the First Court of Appeals in Houston, Texas. On August 24, 2006, BROG filed its Supersedeas Bond to secure payment of the balance of the Arbitration Award, plus interest, if the appeal is dismissed or BROG does not perform the adverse judgment which becomes final on appeal. BROG filed its Brief of Appellant in the First Court of Appeals on November 29, 2006 and the Trust filed its Brief of Appellee on January 29, 2007. BROG was entitled to file its reply brief on or before February 20, 2007, but on February 16, 2007, BROG filed a motion requesting an extension through March 22, 2007. Once all briefs are filed, the parties will await either a ruling on their respective requests to present oral arguments or a ruling on the merits based solely on the briefs. No reliable estimate can be given as to when the First Court of Appeals will act and it should be noted that the ruling of that Court on the merits of the appeal will itself be subject to possible discretionary review by the Texas Supreme Court.

8. Proved Oil and Gas Reserves (unaudited)

Proved oil and gas reserve information is included in Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.

No 16

9. Quarterly Schedule Of Distributable Income (unaudited)

The following is a summary of the unaudited quarterly schedule of Distributable Income for the two years ended December 31, 2006 (in thousands, except unit amounts):


					DISTRIBUTABLE
	ROYALTY		DISTRIBUTABLE		INCOME AND
	INCOME		INCOME		DISTRIBUTION PER UNIT
2006
First Quarter	$	50,481	$	50,490	$	1.083276
Second Quarter		28,532		27,933		.599299
Third Quarter		30,780		31,087		.666989
Fourth Quarter		26,519		26,357		.565491

TOTAL	$	136,312	$	135,867	$	2.915055


2005
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
TOTAL	$	153,858	$	151,560	$	3.251747

Report of Independent Registered Public Accounting Firm

WE HAVE AUDITED THE ACCOMPANYING STATEMENTS of assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2006 and 2005 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006. 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, 2006 and 2005 and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006, 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, 2006, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2007, expressed an unqualified opinion thereon.



Weaver and Tidwell, L.L.P.

Fort Worth, Texas
February 28, 2007

No 17

Glossary of Terms

Aggregate Monthly Distribution: An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a calendar month plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves.

BBL: Barrel, generally 42 U.S. gallons measured at 60°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.

Coal Seam Well: A well completed to a coal deposit found to contain and emit natural gas.

Commingled Well: A well which produces from two or more formations through a common well casing and a single tubing string.

Conventional Well: A well completed to a formation historically found to contain deposits of oil or gas (for example, in the San Juan Basin, the Pictured Cliffs, Dakota and Mesaverde formations) and operated in the conventional manner.

Depletion: The exhaustion of a petroleum reservoir; the reduction in value of a wasting asset by removing minerals; for tax purposes, the removal and sale of minerals from a mineral deposit.

Distributable Income: An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a given period plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves.

Dual Completion: The completion of a well into two separate producing formations at different depths, generally through one string of pipe producing from one of the formations, inside of which is a smaller string of pipe producing from the other formation.

Estimated Future Net Revenues: An estimate computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by Federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves,and assuming continuation of existing economic conditions; sometimes referred to as “estimated future net cash flows.”

Grantor Trust: A trust (or portion thereof) with respect to which the grantor or an assignee of the grantor, rather than the trust, is treated as the owner of the trust properties and is taxed directly on the trust income for federal income tax purposes under Sections 671 through 679 of the Internal Revenue Code of 1986, as amended.

Gross Acres or Wells: The interests of all persons owning interests in such acres or wells.

Gross Proceeds: The amount received by BROG (or any subsequent owner of the Underlying Properties) from the sale of the production attributable to such interests.

Infill Drilling: The drilling of wells intended to be completed to proven reservoirs or formations, sometimes occurring in conjunction with regulatory approval for increased density in the spacing of wells.

Lease Operating Expenses: Expenses incurred in the operation of a producing property as apportioned among the several parties in interest.

MCF: 1,000 cubic feet; the standard unit for measuring the volume of natural gas.

MMBTU: One million British thermal units.

Multiple Completion Well: A well which produces simultaneously through separate tubing strings from two or more producing horizons or alternatively from each.

Net Acres or Wells: The interests of BROG in such acres or wells.

Net Overriding Royalty Interest: A share of gross production from a property, measured by net profits from operation of the property and carved out of the working interest, i.e., a net profits interest.

Net Proceeds: The excess of Gross Proceeds received by BROG during a particular period over Production Costs for such period.

Payadd: Completion in an existing well of additional productive zone(s) within a producing formation.

Present Value Of Estimated Future Net Revenues: The present value of the Estimated Future Net Revenues computed using a discount rate of 10%.

Production Costs: Costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and non-capital costs and including, for example, development drilling, production and processing costs, applicable taxes and operating charges.

Proved Developed Reserves: Those Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved Reserves: Those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.

Proved Undeveloped Reserves: Those Proved Reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.

Recavitated Well: A coal seam well, the production from which has been enhanced or extended by the enlargement of the cavity within the coal deposit to which the well has been completed.

Recompleted Well: A well completed by drilling a separate well bore from an existing casing in order to reach the same reservoir, or re-drilling the same well bore to reach a new reservoir after production from the original reservoir has been abandoned.

Royalty: The principal asset of the Trust; the 75% net overriding royalty interest conveyed to the Trust on November 3,1980, by Southland Royalty Company, the predecessor to BROG, which was carved out of the Underlying Properties.

Royalty Income: The monthly Net Proceeds attributable to the Royalty.

Section 45K tax credit: A Federal income tax credit available under Section 45K of the Internal Revenue Code of 1986, as amended, for coal seam gas (and certain other nonconventional fuels) that was (i) sold prior to January 1, 2003 and (ii) produced from wells drilled (or certain later recompletions treated as wells drilled) after December 31,1979, but prior to January 1, 1993.

Spot Price: The price paid for gas, oil or oil products sold under contracts for the purchase and sale of such minerals on a short-term basis.

Underlying Properties: The working, royalty and other interests owned by Southland Royalty Company, the predecessor to BROG, in properties located in the San Juan Basin of northwestern New Mexico, out of which the Royalty was carved.

Units of Beneficial Interest: The units of ownership of the Trust, equal to the number of shares of common stock of Southland Royalty Company outstanding at the close of business on November 3,1980.

Working Interest: The operating interest under an oil and gas lease.

san juan royalty trust

Campass Bank, Trustee

2525 Ridgmar Boulevard, Suite 100 ~S.CONT Fort Worth, Texas 76116 Toll-free telephone: 966.809.4553 www.sjbrt.com sjt@compassbank.com

auditors Weaver and Tidwell, L.L.P. Dallas, Texas

transfer Agent Computershare Investor Services P.O. Box 43078 Providence, RI 02940-43078 www.computershare.com

for question about distribution checks, address change, and transfer providers call 312-360-5154