EXHIBIT 13

SAN JUAN BASIN ROYALTY TRUST
2003 ANNUAL REPORT & FORM 10-K

For generations, explorers, frontiersmen, miners and ranchers have been drawn to New Mexico. The natural resources that attracted them to the area are the same ones that provide opportunities for us today. And as we examine the history they left behind in decaying ruins and abandoned mines, we’re reminded that no matter how much things change, our fascination with the land and its hidden treasures will always remain the same.

LAKE VALLEY, NEW MEXICO

Like so many ghost towns, Lake Valley had its humble beginnings, prosperous heydays and tragic ending. In 1882, John Leavitt discovered a huge cavern lined with solid silver — later named “The Bridal Chamber” for its crystal-encrusted walls. But as is often the case, with wealth comes trouble. Lake Valley became known for its lawlessness. So to bring order, Jim Courtright, a.k.a. “Longhair Jim,” was hired as town marshall in 1882. After that, things settled down — in more ways than one. In 1893, silver was devalued, propelling the town into a downward slide. Then in 1895, most of Main Street burned to the ground. Today, Lake Valley is managed by the Bureau of Land Management, which has begun a program to protect the area and stabilize some of the structures.

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 in properties located in the San Juan Basin of northwestern New Mexico (the “Underlying Properties”).

UNITS OF BENEFICIAL INTEREST

     The units of beneficial interest of the Trust (the “Units”) are traded on the New York Stock Exchange under the symbol “SJT.” At March 8, 2004, the closing price of a Unit was $19.93. From January 1, 2002, to December 31, 2003, the quarterly high and low closing sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows:

					Distributions
	High		Low		Paid
2003
First Quarter	$	15.8700	$	13.6500	$	.418337
Second Quarter		19.7600		14.3700		.549655
Third Quarter		18.0800		16.1300		.511093
Fourth Quarter		21.8900		18.0900		.459559
TOTAL FOR 2003					$	1.938644
2002
First Quarter	$	11.9000	$	9.2500	$	.075673
Second Quarter		12.2300		10.4900		.193414
Third Quarter		11.8800		9.7000		.263820
Fourth Quarter		13.9000		11.7000		.248447
TOTAL FOR 2002					$	.781354

     At March 8, 2004, there were 46,608,796 Units outstanding held by 1,972 Unit holders of record. The following table presents information relating to the distribution of record ownership of Units:

	NUMBER OF
TYPE OF UNIT HOLDERS	UNIT HOLDERS		UNITS HELD
Individuals, Individual Retirement Accounts, Joint Holders and Minors		1,731		1,991,139
Fiduciaries		188		482,177
Clubs, Associations or Societies		8		89,335
Banks		8		17,285
Depositories		1		43,688,821
Corporations		35		339,209
Government Bodies		1		830
TOTAL		1,972		46,608,796

1

TO UNIT HOLDERS

     We are pleased to present the 2003 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, 2003, without exhibits. The Form 10-K contains important information concerning the Underlying Properties, 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, as defined below, and the successor, through a series of assignments and mergers, to Southland Royalty Company (“Southland Royalty”). T 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 in properties in the San Juan Basin of northwestern New Mexico (the “Underlying Properties”). The Royalty is the principal asset of the Trust. T Under the Indenture governing the Trust, TexasBank, as Trustee, has the primary function of collecting monthly net proceeds (“Royalty Income”) attributable to the Royalty and making the monthly distributions to the Unit holders after deducting administrative expenses and any amounts necessary for cash reserves. T Income distributed to Unit holders in 2003 was $90,357,837 or $1.938644 per Unit. Distributable Income for 2003 consisted of Royalty Income of $91,997,262 plus interest income of $43,882, less administrative expenses of $1,683,307. T 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. T 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. T 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, 2004, and for the year ending December 31, 2004. Unit holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request. T For 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
By:
Lee Ann Anderson Vice President and Trust Officer

2

SHAKESPEARE, NEW MEXICO

As home to such colorful characters as Bean Belly Smith, Russian Jack, Flora Belle, Happy Bob Fambo and Curley Bill, Shakespeare was a mining town that benefited mainly from its reliable water source. This small spring attracted Indians, Spaniards and even a skinny blond kid with buck teeth to town who was looking for a job. He was too young and small for heavy work so he found employment washing dishes in the Stratford Hotel. After he left Shakespeare, he eventually made his way to Lincoln County, where he became known as “Billy the Kid.” After frequent name changes, a fraudulent diamond strike to lure rich East-coast investors, and a gunfight over a breakfast egg, Shakespeare will always be known as one of the most interesting towns in New Mexico. And while many buildings remain today, several were severely damaged by a recent fire.

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 interests 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”). 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 3,946 gross (1,170 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, 2003, the production index for the Underlying Properties is estimated to be approximately 9.65 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. Independent petroleum engineers retained by the Trust have estimated the Underlying Properties could remain productive well beyond the stated production index. 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 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 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 $500,000. 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 presence of heavier hydrocarbons such as ethanes, propanes and butanes 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 2003 production month was approximately 40.6% of the total gas production for that month.

     Sales of production from coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits through 2002. Although both houses of Congress are presently considering energy legislation, including provisions to extend or reinstate the Section 29 credit in various ways, whether such provisions will be enacted into law, and if so, the effect thereof on the Trust and the Unit holders is, at present, unknown. For 2002, the credit was approximately $1.09 per MMBtu. Even though the Section 29 credit does not apply to qualified fuel sold in 2003, a Section 29 credit in the amount of $.02 per Unit may apply to proceeds received in 2003 for qualified fuel sold in 2002 and earlier years for cash basis Unit holders that held Units during January and February 2003. The Internal Revenue Service has issued a private letter ruling to another taxpayer to the effect that cash method taxpayers may claim the Section 29 credit in a later year for sales of qualified fuel in an earlier year where the proceeds from such sales are received in the later year. Because a private letter ruling may be relied on only by the taxpayer who requested the ruling, the Trust applied for a similar ruling. Tax counsel to the Trust has been informed that the Internal Revenue Service intends to issue a Revenue Procedure in the near future allowing a cash basis taxpayer to report the Section 29 credit in either the year the qualifying production is sold or the year the income is received, provided that the taxpayer is consistent in its treatment from year to year and that, accordingly, it will not issue private letter rulings on this question. No assurance can be given, however, whether, or when, such a Revenue Procedure will be issued.

     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

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TRUSTEE’S DISCUSSION & ANALYSIS

GAS AND OIL PRODUCTION

     Total gas and oil production from the Underlying Properties for the five years ended December 31, 2003, were as follows:

	2003		2002		2001		2000		1999
Gas — Mcf		45,202,576		46,206,297		42,960,149		42,220,260		39,940,175
Mcf per Day		123,843		126,593		117,699		115,356		109,425
Oil — Bbls		74,727		93,659		92,413		97,330		72,223
Bbls per Day		205		257		253		266		198

     Royalty Income for the calendar year is associated with actual gas and oil production during the period from November of the preceding year through October of the current year. Gas and oil sales attributable to the Royalty for the past five years are summarized in the following table:

	2003		2002		2001		2000		1999
Gas — Mcf		25,922,650		19,584,056		19,272,021		20,317,750		19,527,666
Average Price (per Mcf)	$	3.93	$	2.32	$	4.61	$	2.99	$	1.78
Oil — Bbls		43,123		40,215		42,056		47,411		35,341
Average Price (per Bbl)	$	26.11	$	20.90	$	24.99	$	24.66	$	14.41

     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 has entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties. These contracts provide for (i) the sale of such gas to Duke Energy and Marketing L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year to year thereafter until terminated by either party on 12 months notice, and (iii) for the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of northwestern New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips Company pursuant to an Assignment and Novation Agreement. Prior to April 1, 2002, the gas produced from the Underlying Properties was sold to Duke Energy and Marketing L.L.C.

     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.

5

 TRUSTEE’S DISCUSSION & ANALYSIS

ROYALTY INCOME

     Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income for the five years ended December 31, 2003, was determined as shown in the following table:

	2003			2002			2001			2000			1999
GROSS PROCEEDS FROM THE UNDERLYING PROPERTIES:
Gas	$	175,653,183		$	103,349,299		$	169,052,231		$	124,902,689		$	69,928,312
Oil		1,938,972			1,863,827			2,233,071			2,409,158			1,028,862
Other		(1,202,368	)(1)		(5,110,589	)(2)		0			4,653,333	(3)		1,189,996	(4)
TOTAL	$	176,389,787		$	100,102,537		$	171,285,302		$	131,965,180		$	72,147,170
LESS PRODUCTION COSTS:
Capital Expenditures		20,590,704			21,470,777			32,999,973			25,575,657			10,556,159	(5)
Severance Tax — Gas		17,281,986			9,752,508			16,687,074			12,059,286			7,180,973
Severance Tax — Oil		174,750			151,594			202,113			234,462			106,335
Other		41,850			18,037			55,000			129,161			(95,445	)
Lease Operating Expenses and Property Taxes		15,637,481			15,701,740			15,109,139			13,906,916	(5)		10,896,526
TOTAL		53,726,771			47,094,656			65,053,299			51,905,482			28,644,548
Excess Production Costs		0			(2,259,628	)(6)		2,259,628	(6)		0			0
Interest on Excess Production Costs		0			(10,545	)(6)		0			0			0
Net Profits		122,663,016			50,737,708			108,491,631			80,059,698			43,502,622
Net Overriding Royalty Interest		75	%		75	%		75	%		75	%		75	%
Royalty Income	$	91,997,262		$	38,053,281		$	81,368,723		$	60,044,773		$	32,626,966

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

(2) 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).

(3) Included in 2000 Distributable Income, as defined below, was a payment by BROG to the Trust in June 2000 of $3,490,000. In June 2000, the Trust and BROG entered into a partial settlement of a claim relating to a gas imbalance. A gas imbalance occurs when more than one party is entitled to the economic benefit of the production of natural gas, but the gas is sold for the account of less than all the parties. Under the terms of the partial settlement, BROG paid the Trust $3,490,000 to settle the imbalance insofar as it relates to some of the wells located on the subject properties.

(4) Included in 1999 Distributable Income was a payment by BROG to the Trust in March 1999 of $892,498. After a pipeline rupture disrupted a significant flow of gas from BROG properties, BROG filed claims with insurance carriers and subsequently received payments of its claims. Some of the claims filed related to properties burdened by the Royalty. The amount of insurance proceeds applicable to such properties was determined to be $1,189,996, of which the Trust received 75% or $892,498.

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

(6) See Note 8 to the Financial Statements included herein.

DISTRIBUTABLE INCOME

     Distributable Income consists of Royalty Income plus interest, less the general and administrative expenses of the Trust and any changes in cash reserves established by the Trustee.

     For the year ended December 31, 2003, Distributable Income was $90,357,837, representing a 148% increase from 2002. For the year ended December 31, 2002, Distributable Income was $36,417,967, representing a 55% decrease from 2001. Distributable Income in 2001 was $80,126,202.

     The Trust received Royalty Income of $91,997,262 and interest income of $43,882 in 2003. After deducting administrative expenses of $1,683,307, Distributable Income for 2003 was $90,357,837 ($1.938644 per Unit). In 2002, Royalty Income was $38,053,281, interest income was $16,112, administrative expenses were $1,728,187, and cash reserves decreased $76,761, resulting in Distributable Income of $36,417,967 ($0.781354 per Unit). The 148% increase in Distributable Income from 2002 to 2003 was primarily attributable to higher gas and oil prices which resulted in increased Royalty Income. Distributable Income for 2003 exceeds 2001 primarily due to decreased capital expenditures in 2003 as compared to 2001. In addition, interest earnings in 2003 were higher, as compared to 2002, primarily due to an increase in funds available for investment. Administrative expenses were slightly lower in

6

 TRUSTEE’S DISCUSSION & ANALYSIS

2003, as compared to 2002, primarily as a result of differences in timing in the receipt and payment of these expenses.

     In 2001, the Trust received Royalty Income of $81,368,723 and interest income of $165,676. After deducting administrative expenses of $1,216,577, Distributable Income for 2001 was $80,126,202 ($1.719123 per Unit). The 55% decrease in Distributable Income from 2001 to 2002 was primarily attributable to lower gas and oil prices as well as the loss of the Val Verde Credit. In addition, interest earnings in 2002 were lower, as compared to 2001, primarily due to a decrease in funds available for investment and lower interest rates in 2002. Administrative expenses were higher primarily because administrative expenses in 2002 included expenses incurred in addressing certain marketing and joint interest audit disputes between the Trust and BROG, as well as expenses incurred in conducting a special meeting of Unit holders to appoint a successor Trustee of the Trust and to approve amendments to the Indenture governing the Trust. See Note 12 to the Financial Statements included herein.

OPERATING EXPENSES

     Monthly operating expenses of the Underlying Properties, exclusive of property taxes, in 2003 averaged approximately $1,250,600, which is lower than the $1,262,900 average in 2002 and higher than the $1,242,200 average in 2001. Operating expenses for 1999 through 2001 include the impact of the annual inclusion of $250,000 from BROG as an offset to lease operating expenses in connection with the settlement of the litigation described in Note 5 to the accompanying Financial Statements. The final $250,000 offset was made in December 2001.

SETTLEMENTS

     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 $10,750,000.

CAPITAL EXPENDITURES

     In February 2003, BROG announced an estimated capital budget for the Underlying Properties of $14.1 million. During the year, the estimate was initially increased to $18.0 million, and ultimately increased to approximately $21.1 million. BROG’s capital plan for the Underlying Properties for 2003 estimated 351 projects, including the drilling of 38 new wells to be operated by BROG and 26 new wells to be operated by third parties. In 2003, BROG actually participated in 509 projects, including the drilling of 58 new wells operated by BROG as well as 10 other wells operated by third parties. BROG reported that the swings in the budget estimates related in large part to whether and when BROG was successful in obtaining the necessary governmental and landowner approvals to drill on a well-by-well basis.

     The aggregate capital expenditures reported by BROG in calculating Royalty Income for 2003 include approximately $6.5 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 Royalty 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 $14.6 million for 2003 budgeted projects were used in calculating Royalty Income in calendar year 2003, and approximately $5.3 million in capital expenditures was used in calculating Royalty Income for January and February 2004.

7

 TRUSTEE’S DISCUSSION & ANALYSIS

Therefore, an additional approximately $1.2 million in capital expenditures for 2003 projects remains to be spent.

     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, 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 (3.56 net) conventional payadds, 54 gross (14.43 net) coal seam wells, six gross (1.62 net) coal seam recompletions, one gross (.002 net) recavitation and six gross (.20 net) miscellaneous coal seam capital projects in progress as of December 31, 2003.

     During 2002, in calculating Royalty Income, BROG deducted approximately $21.5 million of capital expenditures for projects, including drilling and completion of 98 gross (30.05 net) conventional wells, recompletion of 36 gross (14.44 net) conventional wells, 13 gross (2.21 net) miscellaneous capital projects, one gross (.82 net) restimulation, one gross (.05 net) payadd, 16 gross (5.42 net) coal seam wells, 11 gross (1.45 net) miscellaneous coal seam capital projects, 14 gross (5.77 net) coal seam recompletions, five gross (.98 net) coal seam recavitations and three gross (.01 net) coal seam restimulations and facilities maintenance. There were 61 gross (24.49 net) new conventional wells, 20 gross (4.69 net) conventional well recompletions, 65 gross (19.82 net) miscellaneous conventional capital projects, four gross (1.41 net) coal seam wells, two gross (.99 net) coal seam recompletions and five gross (1.72 net) miscellaneous coal seam capital projects in progress as of December 31, 2002.

     During 2001, in calculating Royalty Income, BROG deducted approximately $33 million of capital expenditures for projects, including drilling and completion of 92 gross (36.33 net) conventional wells, recompletion of 33 gross (18.18 net) conventional wells, 13 gross (2.85) net miscellaneous capital projects, three gross (2.34 net) restimulations, 56 gross (8.40 net) conventional payadds, 10 gross (1.52 net) coal seam wells, four gross (1.61 net) coal seam recompletions, one gross (.88 net) coal seam payadd, six gross (.04 net) coal seam recavitations and facilities maintenance. There were 100 gross (32.47 net) new conventional wells, 31 gross (13.47 net) conventional well recompletions, two gross (.87 net) miscellaneous conventional capital projects, nine gross (3.17 net) conventional payadds, 15 gross (1.09 net) conventional restimulations, 12 gross (5.36 net) coal seam wells, seven gross (4.11 net) coal seam recompletions, two gross (.02 net) coal seam restimulations and six gross (.29 net) miscellaneous coal seam capital projects in progress as of December 31, 2001.

     For 2004, BROG’s announced plan for the Underlying Properties includes 441 projects at an aggregate cost of $18.5 million. Approximately $11.7 million of that budget is allocable to new wells, with approximately 61% of those wells projected to be drilled to formations producing coal seam gas as distinguished from conventional gas. BROG reports that based on its actual capital requirements, its mix of projects and swings in the price of natural gas, the actual capital expenditures for 2004 could range from $15 million to $25 million. BROG has indicated that, principally as a result of the OCD’s approval of reduced, 160-acre spacing in the Fruitland Coal formation, BROG’s budget for 2004 reflects a continued focus on that formation.

     BROG indicates its budget for 2004 reflects continued significant development of conventional formations, including infill drilling to the Mesaverde and Dakota formations, development of the Fruitland Coal formation and multiple formation completions. A majority of the new wells for 2004 are projected to be drilled on Underlying Properties in which the fractional working interest included in the Underlying Properties is relatively low, but many of the recompletions and restimulations are scheduled on properties in which such working interest is relatively high.

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 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).

8

 TRUSTEE’S DISCUSSION & ANALYSIS

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, the rules and regulations of the NYSE and the Sarbanes-Oxley Act of 2002. 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 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. For example, the Commission is required to adopt rules and regulations pursuant to the Sarbanes-Oxley Act of 2002 that would require a publicly-traded company’s board of directors, audit committee or executive directors (or similar body) to act with respect to certain corporate governance matters. The Trust does not have, nor does the Indenture governing the Trust provide for, a board of directors, an audit committee or any executive officers. Accordingly, the Trust could not literally comply with such rules and regulations. It is the Trustee’s intention to follow the Commission’s and the 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.

     During the year, the Commission adopted rules implementing legislation concerning governance matters for publicly-held entities that was passed as part of the Sarbanes-Oxley Act of 2002. In addition, the NYSE adopted additional corporate governance rules. Not all of the governance requirements are applicable to 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:

     T Royalty Income recorded for a month is the amount computed and paid by BROG to the Trustee for the Trust.

     T Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies.

     T Distributions to Unit holders are recorded when declared by the Trustee.

     T The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over gross proceeds from such properties must be recovered from future net profits before Royalty Income is again paid to the Trust.

     The financial statements of the Trust differ from financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus instead of an expense.

9

 TRUSTEE’S DISCUSSION & ANALYSIS

RESULTS OF THE 4TH QUARTERS OF 2003 & 2002

     For the three months ended December 31, 2003, Distributable Income was $21,419,523 ($.459559 per Unit), which was more than the $11,579,818 ($.248447 per Unit) of income distributed during the same period in 2002. The increase in Distributable Income resulted primarily from higher average gas and oil prices.

     Royalty Income of the Trust for the fourth quarter is associated with actual gas and oil production during August through October of each year. Gas and oil sales for the quarters ended December 31, 2003 and 2002 were as follows:

	2003		2002
UNDERLYING PROPERTIES
Gas — Mcf		11,677,586		11,608,135
Mcf per Day		126,930		126,175
Average Price (per Mcf)	$	3.71	$	2.30
Oil — Bbls		17,216		19,624
Bbls per Day		187		213
Average Price (per Bbl)	$	25.77	$	23.61
ATTRIBUTABLE TO THE ROYALTY
Gas — Mcf		6,453,617		5,574,600
Oil — Bbls		9,532		9,184

     The average price of gas and oil increased in 2003 compared to the prior year. The price per barrel of oil during the fourth quarter of 2003 was $2.16 per Bbl higher than that received in the fourth quarter of 2002 due to increases in oil prices in world markets generally, including the posted price applicable to the Royalty. Gas production increased slightly primarily due to increased demand.

     Capital costs for the fourth quarter of 2003 totaled $6,861,521 compared to $4,653,069 during the same period of 2002. The increase was primarily due to increased drilling activity in the fourth quarter of 2003. Lease operating expenses and property taxes for the fourth quarter of 2003 averaged $1,163,120 per month compared to $1,322,655 per month in the fourth quarters of 2002.

     Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarter of 2003 and 2002 were as follows:

	2003		2002
October	$	.143777	$	.115816
November		.166295		.043379
December		.149487		.089252
QUARTER TOTAL	$	.459559	$	.248447

10

CHLORIDE, NEW MEXICO

With a history of bullfights and bare-handed battles with bears, this one-time tent camp grew to a full-fledged town within six months of its first silver strike. An active imagination can take one back to what Chloride was like in the 1880s when eight saloons, three general stores, two barber shops, a Chinese laundry and a hotel were part of the thriving economy. But the town lacked one thing: women. In an attempt to overcome this scarcity, a free building site was offered to the first lady who moved to Chloride. It must have worked, because in 1882 the local newspaper reported that the city had at least one brothel, and probably more. Today, Chloride is truly a ghost town. The pioneer store is a museum and the old hanging tree still grows in the middle of Main Street.

SAN JUAN BASIN ROYALTY TRUST

     STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

     December 31, 2003 and 2002

ASSETS	2003		2002
Cash and Short-Term Investments	$	7,082,284	$	4,274,790
Net Overriding Royalty Interests in Producing Oil and Gas Properties — Net		29,822,820		33,697,906
TOTAL	$	36,905,104	$	37,972,696
LIABILITIES AND TRUST CORPUS
Distribution Payable to Unit Holders	$	6,967,426	$	4,159,932
Cash Reserves		114,858		114,858
Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding		29,822,820		33,697,906
TOTAL	$	36,905,104	$	37,972,696

     STATEMENTS OF DISTRIBUTABLE INCOME

     For the Three Years Ended December 31, 2003

	2003		2002			2001
Royalty Income	$	91,997,262	$	38,053,281		$	81,368,723
Interest Income		43,882		16,112			165,676
		92,041,144		38,069,393			81,534,399
Expenditures — General and Administrative		1,683,307		1,728,187			1,216,577
Change in Cash Reserves		—		(76,761	)		191,620
Distributable Income	$	90,357,837	$	36,417,967		$	80,126,202
Distributable Income Per Unit (46,608,796 units)	$	1.938644	$	0.781354		$	1.719123

     STATEMENTS OF CHANGES IN TRUST CORPUS

     For the Three Years Ended December 31, 2003

	2003			2002			2001
Trust Corpus, Beginning of Period	$	33,697,906		$	37,859,749		$	40,686,854
Amortization of Net Overriding Royalty Interest		(3,875,086	)		(4,161,843	)		(2,827,105	)
Distributable Income		90,357,837			36,417,967			80,126,202
Distribution Declared		(90,357,837	)		(36,417,967	)		(80,126,202	)
Trust Corpus, End of Period	$	29,822,820		$	33,697,906		$	37,859,749

The accompanying Notes to Financial Statements are an integral part of these statements.

12

NOTES TO FINANCIAL STATEMENTS

SAN JUAN BASIN ROYALTY TRUST

1. TRUST ORGANIZATION AND PROVISIONS

     The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. As of September 30, 2002, TexasBank (“Trustee”) replaced Bank One, N.A., as Trustee for the Trust. Southland Royalty Company (“Southland Royalty”) conveyed to the Trust a 75% net overriding royalty interest (“Royalty”) carved out of Southland’s working interests and royalty interests in the properties located in the San Juan Basin in northwestern New Mexico (the “Underlying Properties”).

     On November 3, 1980, units of beneficial interest (“Units”) in the Trust were distributed to the Trustee for the benefit of Southland Royalty’s shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland Royalty’s common stock held. The Units are traded on the New York Stock Exchange.

     The terms of the Trust Indenture provide, among other things, that:

T 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;

T 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;

T The Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount;

T The Trustee is authorized to borrow funds to pay liabilities of the Trust; and

T 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, 2003 and 2002 aggregated $103,452,708 and $99,577,622 respectively.

3. BASIS OF ACCOUNTING

     The Financial Statements of the Trust are prepared on the following basis:

T Royalty Income recorded for a month is the amount computed and paid by the owner of the Underlying Properties, Burlington Resources Oil & Gas Company LP (“BROG”), to the Trustee for the Trust. Royalty Income consists of the amounts received by the owner of the Underlying Properties from the sale of production less applicable accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%.

T Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies.

T Distributions to Unit holders are recorded when declared by the Trustee.

T The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over net proceeds from such properties must be recovered from future net profits before Royalty Income is again paid to the Trust. The Financial Statements of the Trust differ from Financial Statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus instead of an expense.

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.

13

T NOTES TO FINANCIAL STATEMENTS T

     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 production from coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits through 2002. Although both houses of Congress are presently considering energy legislation, including provisions to extend or reinstate the Section 29 credit in various ways, whether such provisions will be enacted into law, and if so, the effect thereof on the Trust and the Unit holders is at present, unknown. Even though the Section 29 credit does not apply to qualified fuel sold in 2003, a Section 29 credit (at the rate applicable in 2002) may apply to proceeds received in 2003 for qualified fuel sold in 2002 and earlier years for Unit holders that utilize the cash method of tax accounting. The Internal Revenue Service has issued a private letter ruling to another taxpayer to the effect that cash method taxpayers may claim the Section 29 credit in a later year for sales of qualified fuel in an earlier year where the proceeds from such sales are received in the later year. Because a private letter ruling may be relied on only by the taxpayer who requested the ruling, the Trust applied for a similar ruling. Tax counsel to the Trust has been informed that the Internal Revenue Service intends to issue a Revenue Procedure in the near future allowing a cash basis taxpayer to report the Section 29 credit in either the year the qualifying production is sold or the year the income is received, provided that the taxpayer is consistent in its treatment from year to year and that, accordingly, it will not issue private letter rulings on this question. No assurance can be given, however, whether, or if so when, such a Revenue Procedure will be issued.

     To benefit from the credit in 2003, each cash basis Unit Holder must determine from the tax information the Unit Holder received from the Trust, its pro rata share of qualifying production of the Trust sold before January 1, 2003, based upon the number of Units owned during each month of the year, and the amount of available credit per MMbtu for the year, and then apply the tax credit against the Unit Holder’s own income tax liability, but such credit could not reduce the Unit Holder’s regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below its tentative minimum tax. Section 29 also provides that any amount of Section 29 credit disallowed for the tax year solely because of this limitation will increase a taxpayer’s credit for prior year minimum tax liability, which may be carried forward indefinitely as a credit against the taxpayer’s regular tax liability, subject, however, to the limitations described in the preceding sentence. There is no provision for the carryback or carryforward of the Section 29 credit in any other circumstance.

     BROG has historically provided to the Trust summary Section 29 tax credit information related to Trust properties. In 1999, the U.S. Court of Appeals for the 10th Circuit upheld the position of the Internal Revenue Service and the Tax Court that nonconventional fuel such as coal seam gas does not qualify for the Section 29 credit unless the producer has received an appropriate well category determination from the Federal Energy Regulatory Commission. Substantially all of the wells burdened by the Royalty have received the appropriate well category certification. BROG has informed the Trustee that it will continue to seek certification of any qualified but not certified wells burdened by the Royalty. Unless the Section 29 credit is extended or reinstated in such a way as to include previously drilled wells, however, these actions will not affect the Trust or its Unit holders in periods after December 31, 2002.

     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. LITIGATION SETTLEMENT

     On September 4, 1996, the Trustee announced the settlement of litigation between the Trust and BROG. In the settlement, BROG agreed (i) to pay $19,750,000 in cash plus interest earning thereon from September 5, 1996, in settlement of underpayment of royalty claims of the Trust; and (ii) commencing in 1997, to credit the Trust with $250,000 per year for five years as an offset against lease operating expenses chargeable to the Trust. BROG also agreed to make certain adjustments that represent cost reductions favorable to the Trust in the ongoing charges for coal seam gas gathering and treating on BROG’s Val Verde system. Additionally, the Trustee and BROG established a formal protocol pursuant to which joint interest auditors retained by the Trustee gained improved access to BROG’s books and records applicable to the Underlying Properties. The final $250,000 payment was received in 2001. In addition, BROG sold the Val Verde gathering system in 2002, thus increasing costs to the Trust.

     Agreement was also reached regarding marketing arrangements for the sale of gas, oil and natural gas liquids products from the Underlying Properties going forward as follows:

     a. BROG agreed that contracts for the sale of gas from the Underlying Properties would require the written approval of an independent gas marketing consultant acceptable to the Trust. For a discussion of the current contract covering the sale of gas from the Underlying Properties, see Note 6.

     b. BROG will continue to market the oil and natural gas liquids from the Underlying Properties but will remit to the Trust actual proceeds from such sales. BROG will no longer use posted prices as the basis for calculating proceeds to the Trust nor

14

T NOTES TO FINANCIAL STATEMENTS T

make a deduction for marketing fees associated with sales of oil or natural gas liquids products.

     c. The Trust retained access to BROG’S current gas transportation, gathering, processing and treating agreements with third parties through the remainder of their primary terms.

6. CERTAIN CONTRACTS

     BROG has entered into two contracts for the sale of all gas from the Underlying Properties. These contracts provide for (i) the sale of Trust gas in two packages to Duke Energy and Marketing L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year to year thereafter until terminated by either party on 12 months’ notice, and (iii) the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of northwestern New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips Company pursuant to an Assignment and Novation Agreement.

     Confidentiality agreements with purchasers of gas produced from the Underlying Properties prohibit public disclosure of certain terms and conditions of gas sales contracts with those entities, including specific pricing terms, gas receipt points, etc. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties.

7. CONTINGENCIES

     Information regarding the status of litigation matters is included in Item 3 of the Trust’s Annual Report on Form 10-K which is included in this report.

8. COMMITMENTS AND CONTINGENCIES

     At December 31, 2001, BROG had incurred excess production costs of $2,259,628 on the Underlying Properties due primarily to high capital costs. The Trust conveyance provides for the deduction of excess production costs in determining Royalty Income until such costs are fully recovered and allows for interest to be charged on excess production costs at the prime rate. Interest in the amount of $10,545 was added to such excess production costs. Of the total, $1,702,630 is attributable to the Trust and has been deducted in determining 2002 Royalty Income. As a result of settlements agreed to among BROG and other third parties concerning the Underlying Properties, the net profits applicable to the Trust were reduced by approximately $3,624,117. This amount was deducted in calculating Royalty Income due the Trust in one million dollar increments in each of May, June and July of 2002, with the balance deducted in August of 2002.

9. SIGNIFICANT CUSTOMERS

     Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is included in Note 6 above and Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.

10. MMS SETTLEMENT

     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.

11. 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.

12. AMENDMENTS TO THE TRUST’S INDENTURE

     At a special meeting of Unit holders on September 30, 2002, the Unit holders appointed TexasBank as the successor Trustee of the Trust. The Unit holders also approved amendments to the Trust’s Royalty Trust Indenture (the “Indenture”) which clarified the language of the Indenture, clarified and expanded the indemnification provisions of the Indenture, and amended the provisions of the Indenture applicable to the fees payable to the Trustee, the investment options available to the Trustee and the manner in which the Trustee can dispose of assets of the Trust.

13. 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, 2003 (in thousands, except unit amounts):

					DISTRIBUTABLE
					INCOME AND
	ROYALTY		DISTRIBUTABLE		DISTRIBUTION
	INCOME		INCOME		PER UNIT
2003
First Quarter	$	19,911	$	19,498	$	.418337
Second Quarter		26,051		25,619		.549655
Third Quarter		24,332		23,821		.511093
Fourth Quarter		21,703		21,420		.459559
TOTAL	$	91,997	$	90,358	$	1.938644
2002
First Quarter	$	3,925	$	3,527	$	.075673
Second Quarter		9,560		9,015		.193414
Third Quarter		12,549		12,296		.263820
Fourth Quarter		12,019		11,580		.248447
TOTAL	$	38,053	$	36,418	$	.781354

15

INDEPENDENT AUDITORS’ REPORT

T TEXASBANK, AS TRUSTEE FOR THE SAN JUAN BASIN ROYALTY TRUST: T

We have audited the accompanying statements of assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2003 and 2002, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2003. 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 auditing standards generally accepted in the United States of America. 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, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2003 and 2002, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2003, on the basis of accounting described in Note 3 to the financial statements. T

Weaver and Tidwell, L.L.P.
Fort Worth, Texas
March 5, 2004

SAN JUAN BASIN ROYALTY TRUST	AUDITORS	TRANSFER AGENT
TexasBank, Trustee	Weaver and Tidwell, L.L.P.	Computershare Investor Services
2525 Ridgmar Boulevard, Suite 100	Fort Worth, Texas	Transfer Services
Fort Worth, Texas 76116		P.O. Box A3480
Toll-free telephone: 866-809-4553	LEGAL COUNSEL	Chicago, Illinois 60609-3480
www.sjbrt.com	Vinson & Elkins L.L.P.
sjt@texasbank.com	Dallas, Texas	For questions about distribution
		checks, address changes and transfer
	TAX COUNSEL	procedures, call 312-360-5154
	Winstead, Sechrest & Minick, PC
	Houston, Texas

16

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 degreesF.

BCF: Billion cubic feet.

BROG: Burlington Resources Oil & Gas Company LP.

BTU: British thermal unit; the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.

COAL SEAM WELL: A well completed to a coal deposit found to contain and emit natural gas.

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

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

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

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

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

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

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

GROSS ACRES OR WELLS: The interests of all persons owning interests in such acres or wells.

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

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

LEASE OPERATING EXPENSES: Expenses incurred in the operation of a producing property as apportioned among the several parties in interest.

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

MMBTU: One million British thermal units.

MULTIPLE COMPLETION WELL: A well which produces simultaneously through separate tubing strings from two or more producing horizons or alternatively from each.

NET ACRES OR WELLS: The interests of BROG in such acres or wells.

NET OVERRIDING ROYALTY INTEREST: A share of gross production from a property, measured by net profits from operation of the property and carved out of the working interest, i.e., a net profits interest.

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

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

PRESENT VALUE OF ESTIMATED FUTURE NET REVENUES: The present value of the Estimated Future Net Revenues computed using a discount rate of 10%.

PRODUCTION COSTS: Costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and 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 29 TAX CREDIT: A federal income tax credit available under Section 29 of the Internal Revenue Code for producing coal seam gas (and other nonconventional fuels) from wells drilled prior to January 1, 1993, to a formation beneath a qualifying coal seam formation, and for production sold before 2003 from wells drilled after December 31, 1979, but prior to January 1, 1993, which are later completed into such a formation.

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

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

UNITS OF BENEFICIAL INTEREST: The units of ownership of the Trust, equal to the number of shares of common stock of Southland Royalty Company outstanding at the close of business on November 3, 1980.

WORKING INTEREST: The operating interest under an oil and gas lease.

Photos (C) Copyright by Daniel Ter-Nedden /www.ghosttowngallery.com

SAN JUAN BASIN ROYALTY TRUST T TEXASBANK, TRUSTEE

2525 RIDGMAR BOULEVARD, SUITE 100 T FORT WORTH, TEXAS 76116 T 866-809-4553 T WWW.SJBRT.COM