UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the Quarterly Period Ended June 30, 2003
or

o Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from            to           

Commission File No. 1-8032

SAN JUAN BASIN ROYALTY TRUST

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

Texas
(State or other jurisdiction
of incorporation or organization) 75-6279898
(I.R.S. Employer
Identification No.)

TexasBank, Trust Department
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas 76116
(Address of principal executive offices)
(Zip Code)

Telephone Number: (866) 809-4553
(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No o

Number of Units of beneficial interest outstanding at August 13, 2003: 46,608,796

TABLE OF CONTENTS

PART I FINANCIAL INFORMATION
	Item 1. Financial Statements.
		CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS
		CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)
		CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)
		NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)
	Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.
	Item 3. Quantitative and Qualitative Disclosures About Market Risk.
	Item 4. Controls and Procedures.
PART II OTHER INFORMATION
	Item 1. Legal Proceedings.
	Item 6. Exhibits and Reports on Form 8-K.
SIGNATURES
INDEX TO EXHIBITS
EX-31 Certification Required by Rule 13a-14(a)
EX-32 Certification Required by Rule 13a-14(b)

SAN JUAN BASIN ROYALTY TRUST

PART I
FINANCIAL INFORMATION

Item 1. Financial Statements.

     The condensed financial statements included herein have been prepared by the independent accountants for the San Juan Basin Royalty Trust (the “Trust”), at the request of TexasBank, the Trustee of the Trust, without audit, pursuant to the rules and regulations of the Securities and Exchange Commission. In accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 47, released September 16, 1982, the Trust continues to prepare its financial statements in a manner that differs from accounting principals generally accepted in the United States of America (“GAAP”); such presentation is customary to other royalty trusts. Certain information and footnote disclosures normally included in annual financial statements have been condensed or omitted pursuant to Rule 10-01 of Regulation S-X promulgated under the Securities and Exchange Act of 1934, although the Trustee believes that the disclosures are adequate to make the information presented not misleading. These condensed financial statements should be read in conjunction with the financial statements and the notes thereto included in the Trust’s annual report on Form 10-K/A for the year ended December 31, 2002. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, necessary to present fairly the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust at June 30, 2003, and the distributable income and changes in trust corpus for the three-month periods and six-month periods ended June 30, 2003 and 2002 have been included. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

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SAN JUAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

	June 30,		December 31,
ASSETS	2003		2002
	(Unaudited)
Cash and short-term investments	$	6,075,502	$	4,274,790
Net overriding royalty interest in producing oil and gas properties (net of accumulated amortization of $101,553,168 and $99,577,622 at June 30, 2003 and December 31, 2002, respectively)		31,722,360		33,697,906
	$	37,797,862	$	37,972,696
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit Holders	$	5,960,644	$	4,159,932
Cash reserves		114,858		114,858
Trust corpus - 46,608,796 Units of beneficial interest authorized and outstanding		31,722,360		33,697,906
	$	37,797,862	$	37,972,696

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2003		2002		2003		2002
Royalty income	$	26,051,389	$	9,559,569	$	45,962,457	$	13,484,924
Interest income		15,801		2,104		23,254		2,851
Decrease in cash reserves		—		—		—		76,761
		26,067,190		9,561,673		45,985,711		13,564,536
General and administrative expenditures		448,456		546,871		868,829		1,022,721
Distributable income	$	25,618,734	$	9,014,802	$	45,116,882	$	12,541,815
Distributable income per Unit (46,608,796 Units)	$	.549655	$	.193414	$	.967992	$	.269087

The accompanying notes to condensed financial statements are an integral part of these statements.

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SAN JUAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2003			2002			2003			2002
Trust corpus, beginning of period	$	32,652,361		$	37,479,045		$	33,697,906		$	37,859,749
Amortization of net overriding royalty interest		(930,001	)		(1,124,730	)		(1,975,546	)		(1,505,434	)
Distributable income		25,618,734			9,014,802			45,116,882			12,541,815
Distributions declared		(25,618,734	)		(9,014,802	)		(45,116,882	)		(12,541,815	)
Total corpus, end of period	$	31,722,360		$	36,354,315		$	31,722,360		$	36,354,315

The accompanying notes to condensed financial statements are an integral part of these statements.

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SAN JUAN BASIN ROYALTY TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

1.	BASIS OF ACCOUNTING
	The San Juan Basin Royalty Trust was established as of November 1, 1980. 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 the working interest owner, 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 interest burdened by the net overriding royalty interest (“Royalty”) 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%.

• 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 overriding royalty interest to the Trust provides that any excess of production costs over gross proceeds must be recovered from future net profits.

	The financial statements of the Trust differ from financial statements prepared in accordance with 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 as an expense. The basis of accounting used by the Trust is widely used by royalty trusts for financial reporting purposes and presents the revenues and expenditures that are actually distributed to the Unit Holders.
2.	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 the tax treatment described above.
	The Trust began receiving royalty income from coal seam gas wells beginning in 1989. Under Section 29 of the Internal Revenue Code, coal seam gas production from wells drilled prior to

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	January 1, 1993 (including certain wells recompleted in coal seam formations thereafter), generally qualifies for the federal income tax credit for producing non-conventional fuels if such production and the sale thereof occurs before January 1, 2003. For 2002, this tax credit was approximately $1.09 per MMBtu. The Trust also receives production from wells producing from a tight sands formation, which likewise generally qualifies for the federal income tax credit for producing non-conventional fuels if such production and the sale thereof occurs before January 1, 2003, and certain other conditions are met. Unlike the credit for coal seam gas, the credit for tight formation gas is not adjusted for inflation, therefore the credit remains fixed at .517241 per MMBtu. For qualifying production of the Trust, each Unit Holder must determine from the tax information the Unit Holder receives from the Trust, its pro rata share of such production 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 may 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 circumstances.
	Although both houses of Congress have passed an energy bill, the final form of the legislation is not yet known. Unless new legislation is passed extending the Section 29 credit on existing eligible production or allowing for a credit on eligible new production for which some portion of the Trust’s production could qualify, there will be no further Section 29 credit on the Trust’s production sold in the year 2003 or later years.
	The Trustee is provided summary Section 29 tax credit information related to Trust properties by BROG, which information is then provided to the Unit Holders. 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 (“FERC”). The FERC’s certification authority expired effective January 1, 1993. However, on July 14, 2000, the FERC issued a final ruling amending its regulations to reinstate certain regulations involving well category determinations for all wells and tight formation areas that could qualify for the Section 29 tax credit. BROG has informed the Trustee that it has identified approximately 250 wells as non-certified. Of those, BROG has determined that six do not qualify for the Section 29 tax credit. BROG has informed the Trustee that it will seek certification of all qualified wells and that two additional wells were certified in 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 will generally be treated as portfolio income and will not reduce passive losses.
3.	CONTINGENCIES
	See Part II — Item 1, “Legal Proceedings” concerning the status of litigation matters.

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4.	SETTLEMENT OF CLAIMS RELATING TO GAS IMBALANCE
	In June 2000, the Trust and BROG entered into a partial settlement of claims relating to a gas imbalance with respect to production from mineral properties currently operated by BROG. Under the terms of the partial settlement BROG paid the Trust $3,490,000 to settle the imbalance insofar as it relates to some of the wells located on the subject properties. The remainder of the imbalance is to be addressed through volume adjustments whereby the Trust’s net overriding royalty interest will be applied to 50% of the overproduced parties’ interest, on a monthly basis, until the imbalance is corrected. The Trust is in communication with BROG in order to determine the estimated value of the volume adjustments and the time during which the remainder of the imbalance will be corrected. Such volume adjustments will be monitored by the Trust’s consultants.
5.	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 royalty income for the six months ended June 30, 2002.
6.	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.

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Item 2. Trustee’s Discussion and Analysis of Financial Condition and Results of Operations.

Forward-Looking Information

     Certain information included in this report contains, and other materials filed or to be filed by the Trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices and the results thereof, and regulatory matters. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements reflect BROG’s current view with respect to future events; are based on our assessment of, and are subject to, a variety of factors deemed relevant by the Trustee and BROG and involve risks and uncertainties. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated.

Three Months Ended June 30, 2003 and 2002

     The Trust received royalty income of $26,051,389 and interest income of $15,801 during the second quarter of 2003. After deducting administrative expenses of $448,456, distributable income for the quarter was $25,618,734 ($.549655 per Unit). In the second quarter of 2002, royalty income was $9,559,569, interest income was $2,104, administrative expenses were $546,871 and distributable income was $9,014,802 ($.193414 per Unit). The tax credit relating to production from coal seam and tight sand wells totaled approximately $.03 per Unit for the second quarter of 2002. Although both houses of Congress have passed an energy bill, the final form of the legislation is not yet known. Unless new legislation is passed extending the Section 29 credit on existing eligible production or allowing for a credit on eligible new production for which some portion of the Trust's production could qualify, there will be no further Section 29 credit on the Trust's production sold in the year 2003 or later years. For further information concerning this tax credit, Unit Holders should refer to the Trust’s Annual Report for 2002. Based on 46,608,796 Units outstanding, the per Unit distributions during the second quarter of 2003 were as follows:

April	$	.158234
May		.263534
June		.127887
Quarter Total	$	.549655

     The royalty income distributed in the second quarter of 2003 was higher than that distributed in the second quarter of 2002, primarily due to an increase in the average gas price from $2.18 per Mcf for the second quarter of 2002 to $4.48 per Mcf for the second quarter of 2003. Interest earnings for the quarter ended June 30, 2003, as compared to the quarter ended June 30, 2002, were higher, primarily due to an increase in funds available for investment. Administrative expenses were lower primarily as a result of differences in timing in the receipt and payment of these expenses but also because administrative expenses in the second quarter of 2002 included expenses incurred in an arbitration proceeding involving BROG and the Trust undertaken to resolve certain gas marketing issues.

     The capital costs attributable to the properties from which the Trust’s Royalty was carved (the “Underlying Properties”) for the second quarter of 2003 were reported by BROG as approximately $2.9 million. BROG’s capital expenditure budget for the Underlying Properties for 2003 is estimated at $14.2 million; however, BROG reports that based on its actual capital requirements, its mix of projects, and swings

8

in the price of natural gas, the actual capital expenditures for 2003 could range from $10 million to $22 million. Capital expenditures were approximately $3.4 million for the second quarter of 2002. In 2002, approximately $21.5 million in capital expenditures were deducted in calculating the Royalty. In February 2003, BROG informed the Trust that for 2003 it anticipates 351 projects, including the drilling of 38 new wells to be operated by BROG and 26 new wells to be operated by third parties. Of the new BROG operated wells, 14 are projected to be conventional wells completed in the Pictured Cliffs, Mesaverde and/or Dakota formations, and the remaining 24 are projected as coal seam wells completed in the Fruitland Coal formation. A total of 21 of the new wells operated by third parties are projected to be conventional wells and the remaining five are predicted to be coal seam wells. BROG projects approximately $10.6 million to be spent on the new wells, and $3.6 million to be expended in working over existing wells and in the maintenance and improvement of production facilities.

     BROG indicates its budget for 2003 reflects continued, significant developments in which the Trust’s net overriding royalty interest is relatively high, as well as a sustained focus in conventional formations, including infill drilling to the Mesaverde and Dakota formations, development of the Fruitland Coal formation and multiple formation completions.

     In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In October 2002, the New Mexico Oil Conservation Division approved reduced, 160-acre spacing in selected portions of the Fruitland Coal formation. BROG has informed the Trust that, principally as a result of this approval, its budget for 2003 reflects a focus on the Fruitland Coal formation. The New Mexico Oil Conservation Division has asked BROG and other interested parties to study whether the change in spacing requirements should be expanded to cover other portions of the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.

     BROG has informed the Trust that lease operating expenses and property taxes were $3,902,841 and $135,000 respectively, for the second quarter of 2003, as compared to $3,663,386 and $71,100, respectively, for the second quarter of 2002.

     BROG has informed the Trustee that during the second quarter of 2003, five gross (2.54 net) conventional wells, 19 gross (.81 net) payadds, 13 gross (9.54 net) restimulations, and eight gross (2.50 net) coal seam wells were completed on the Underlying Properties.

     Fifty-four gross (16.04 net) conventional wells, 19 gross (5.27 net) payadds, 20 gross (5.55 net) recompletions, 18 gross (11.51 net) restimulations, 39 gross (14.25 net) coal seam wells, one gross (.002 net) recavitation, and five gross (.17 net) recompletions were in progress at June 30, 2003.

     Twelve gross (5.16 net) conventional wells, seven gross (1.93 net) conventional recompletions, three gross (2.29 net) coal seam wells, and five gross (1.97 net) coal seam recompletions were completed as of June 30, 2002.

     Sixty-five gross (19.41 net) conventional wells, four gross (0.22 net) conventional recompletions, six gross (2.98 net) coal seam wells, and six gross (3.22 net) coal seam recompletions were in progress as of June 30, 2002.

     “Gross” acres or wells, for purposes of this discussion, means the entire ownership interest of all parties in such properties, and BROG’s interest therein is referred to as the “net” acres or wells. A payadd is the completion of an additional productive interval in an existing completed zone in a well.

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     Royalty income for the quarter ended June 30, 2003 is associated principally with actual gas and oil production during February 2003 through April 2003 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the three months ended June 30, 2003 and 2002 were as follows:

		2003		2002
Gas:
	Total sales (Mcf)		10,454,608		11,129,745
	Mcf per day		117,468		125,053
	Average price (per Mcf)	$	4.48	$	2.18
Oil:
	Total sales (Bbls)		24,381		28,204
	Bbls per day		274		317
	Average price (per Bbl)	$	27.91	$	19.14

Gas and oil sales attributable to the Royalty for the three months ended June 30, 2003 and 2002 were as follows:

	2003	2002
Gas sales (Mcf)	6,498,418	5,252,787
Oil sales (Bbls)	15,091	13,935

     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 that is dependent on such factors as price and cost, including capital expenditures, the aggregate production volumes from the Underlying Properties may not provide a meaningful comparison to volumes attributable to the Royalty.

     During the second quarter of 2003, average gas prices were $2.30 higher than the average prices reported during the second quarter of 2002. The average price per barrel of oil during the second quarter of 2003 was $8.77 per barrel higher than received for the second quarter of 2002 due to increases in oil prices in world markets generally, including the posted prices applicable to oil sales attributable to the Royalty.

     BROG has entered into two contracts for the sale of all volumes of gas subject to the Royalty (the “Trust gas”). 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 Trust gas at various delivery points through March 31, 2005, and from year-to-year thereafter until terminated by either party on twelve months notice, and (iii) for the sale of Trust gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of New Mexico. Unit Holders are referred to Note 6 of the Notes to Financial Statements in the Trust’s 2002 Annual Report for further information concerning the marketing of gas produced from the Underlying Properties. Prior to April 1, 2002, the Trust gas was sold under a contract dated November 10, 1999 between BROG and 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, 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.

Six Months Ended June 30, 2003 and 2002

     For the six months ended June 30, 2003, distributable income was $45,116,882 ($0.967992 per Unit) as compared to the $12,541,815 ($.269807 per Unit) of income distributed during the same period in 2002. The increase in distributable income from 2002 to 2003 resulted primarily from higher gas and oil prices

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during the first half of 2003. Interest income for the six months ended June 30, 2003 was $23,254 compared to $2,851 during the first six months of 2002. This increase is due to the timing of receipt of interest income and an increase in cash to be invested. General and administrative expenses were $869,829 for the six months ended June 30, 2003, as compared to $1,022,721 during the same period in 2002 primarily due to differences in timing of the receipt and payment of these expenses, but also as a result of expenses incurred in 2002 in an arbitration proceeding involving BROG and the Trust, undertaken to resolve certain gas marketing issues.

     Capital expenditures incurred by BROG, attributable to the Underlying Properties, for the first six months of 2003 amounted to approximately $9.4 million. Capital expenditures were approximately $14.7 million for the first six months of 2002. Lease operating expenses and property taxes totaled $7,824,408 and $271,250, respectively, for the first six months of 2003 as compared to $7,799,633 and $146,667, respectively, for the first six months of 2002.

     BROG informed the Trustee that during the six months ended June 30, 2003, 14 gross (9.10 net) conventional wells and three gross (.94 net) miscellaneous capital projects were completed on the Underlying Properties. Thirty-eight gross (1.73 net) payadds and 18 gross (12.74 net) restimulations were completed during the first six months of 2003. During the six months ended June 30, 2003, 15 gross (3.37 net) coal seam wells and two gross (.88 net) coal seam miscellaneous capital projects were completed.

     Royalty income for the six months ended June 30, 2003 is associated with actual gas and oil production during November 2002 through April 2003 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the six months ended June 30, 2003 and 2002 were as follows:

		2003		2002
Gas:
	Total sales (Mcf)		22,092,156		22,600,721
	Mcf per day		122,056		124,866
	Average price (per Mcf)	$	3.97	$	2.19
Oil:
	Total Sales (Bbls)		40,488		49,658
	Bbls per day		224		274
	Average price (per Bbl)	$	26.53	$	18.33

Gas and oil sales attributable to the Royalty for the six months ended June 30, 2003 and 2002 were as follows:

	2003		2002
Gas sales (Mcf)		12,649,546		7,177,930
Oil sales (Bbls)		23,430		18,259

     During the first six months of 2003, gas and oil prices were higher than during the first six months of 2002. Since the oil and gas sales attributable to the Royalty are based on an allocation formula that is dependant 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.

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Calculation of Royalty Income

     Royalty income received by the Trust for the three months and six months ended June 30, 2003 and 2002, respectively, was computed as shown in the following table:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2003			2002			2003			2002
Gross proceeds of sales from the Underlying Properties:
Gas proceeds	$	46,884,002		$	24,268,350		$	87,747,042		$	49,485,237
Oil proceeds		680,484			539,877			1,074,147			910,026
Other		(1,206,368	)		(2,666,666	)		(1,202,368	)		(2,666,666	)
Total		46,362,118			22,141,561			87,618,821			47,728,597
Less production costs:
Severance tax – Gas		4,640,748			2,251,404			8,678,515			4,750,541
Severance tax – Oil		59,305			37,575			93,514			73,529
Lease operating expense and property tax		4,037,841			3,734,486			8,095,658			7,946,300
Other		26,850			5,000			41,850			15,000
Capital expenditures		2,862,189			3,367,004			9,426,009			14,693,156
Total		11,626,933			9,395,469			26,335,545			27,478,526
Less excess production and interest from prior year		—			—			—			2,270,173
Net profits		34,735,185			12,746,092			61,283,276			17,979,898
Net overriding royalty interest		75	%		75	%		75	%		75	%
Royalty income	$	26,051,389		$	9,559,569		$	45,962,457		$	13,484,924

Contractual Obligations

     Under the Trust’s indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates for time in excess of 300 hours annually. In no case will the administrative fee due under items (i) and (ii) above be less than $36,000 per year (as adjusted annually to reflect the increase (if any) since January 1, 2003, 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, 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

12

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 “SEC”) 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 SEC 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 SEC’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.

Critical Accounting Policies

     In accordance with the SEC’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.

• 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 over gross proceeds must be recovered from future net profits.

     The financial statements of the Trust differ from financial statements prepared in accordance with 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. The basis of accounting used by the Trust is widely used by royalty trusts for financial reporting purposes and presents the revenues and expenditures that are actually distributed to the Unit Holders.

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

     The Trust invests in no derivative financial instruments, and has no foreign operations or long-term debt instruments. The Trust is a passive entity and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short term investments acquired with funds held by the Trust pending distribution to Unit Holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit Holders to any foreign currency

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related market risk. The Trust does not market the Trust gas, oil and/or natural gas liquids. BROG is responsible for such marketing.

Item 4. Controls and Procedures.

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

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

     The Trustee has evaluated the Trust’s disclosure controls and procedures within the 90 days prior to the filing of this Quarterly Report on Form 10-Q and has determined that, subject to BROG’s delivery of timely and accurate information to the Trust, such disclosure controls and procedures are effective. The Trustee has not reviewed the Trust’s disclosure controls and procedures in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the indenture pursuant to which the Trust was created provide for, officers, a board of directors or an independent audit committee.

     Subsequent to the Trustee’s evaluation, there were no significant changes in internal controls or other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses.

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PART II
OTHER INFORMATION

Item 1. Legal Proceedings.

Settlements

     An administrative claim was initiated on March 17, 1997 by the Mineral Management Service of the United States Department of the Interior (the “MMS”) against BROG regarding a gas contract settlement dated March 1, 1990, between BROG and certain other parties thereto. The claim alleged that additional royalties were due on production from federal and Indian leases in the State of New Mexico on properties burdened by the Trust. On December 3, 2001, BROG settled this claim by paying the Jicarilla Apache Nation the sum of $2,853,974 and the MMS the sum of $1,224,043. MMS also retained certain overpayments by BROG in the amount of $1,127,623 as part of the settlement. Certain properties included in this settlement are burdened by the Royalty. BROG previously offset the entire $2,853,974 Jicarilla component of the settlement against amounts otherwise distributed in payment of the Royalty, and deducted $901,776 from the April 2003 distribution to the Trust as the Trust’s 75% portion of the remaining $1,224,043 component of the settlement, slightly reduced by agreement of the parties. BROG has indicated that it does not appear that any of the $1,127,623 in overpayments retained by the MMS is attributable to the Trust.

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

Administrative Proceedings

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

     MMS Proceedings

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

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“backhaul” agreement. The demand letter directs BROG to pay additional royalties of $518,304, to recalculate royalties in accordance with the MMS’ interpretation of the regulations and to pay the difference between total royalty due and royalty paid.

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

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

     Due to the similarity of the claims in the Blanco Pool, Affiliate Proceeds Demand and the Coalbed Methane administrative appeals, to the claims in the suits in the In re Natural Gas Royalties qui tam litigation described below, settlement discussions between BROG and the federal government in the gas qui tam litigation will, if successful, include the settlement of each of the MMS Proceedings.

     Jicarilla Indian Tribe Proceedings

     This appeal arises from an MMS Order to Perform dated June 10, 1998. The Order to Perform states that, in valuing production for royalty purposes, BROG must, among other things, perform a major portion analysis (i.e., calculate value on the highest price paid or offered for a major portion of the gas produced from the field where the leased lands are situated). BROG believes that producers do not have access to prices received by other producers in a field, so a major portion calculation must be done by MMS.

Litigation

     In re Natural Gas Royalties Qui Tam Litigation

     BROG and other oil and gas companies have been named as defendants in various lawsuits alleging violations of the civil False Claims Act. These lawsuits were consolidated during 1999 and 2000 for pre-trial proceedings by the United States Judicial Panel on Multidistrict Litigation in the matter of In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming (MDL-1293). The plaintiffs contend that defendants underpaid royalties on natural gas and natural gas liquids produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. Plaintiffs allege that the royalties paid by defendants were lower than the royalties required to be paid under federal regulations and that the forms

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filed by defendants with the MMS reporting these royalty payments were false, thereby violating the civil False Claims Act. The United States has intervened in certain of the MDL-1293 cases as to some of the defendants, including BROG.

     If successful, this litigation could result in a decrease in royalty income received by the Trust. The plaintiffs and the intervenor have not specified in their pleadings the amount of damages they seek from BROG. The Trust has been informed that BROG has established a substantial reserve for potential liability arising from this litigation. However, at this time, no estimate can be made as to the amount of any potential loss in this litigation, or the portion, if any, of such potential loss that would be allocated to the Trust’s interest. Any proposed allocation of loss to the Trust will be reviewed by the Trust’s consultants.

     Quinque Litigation

     In September 1999, BROG was served with a class action petition styled Quinque Operating Company on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, Kansas, naming certain of its current or former affiliates as defendants, along with hundreds of other gas production and gas pipeline companies. On February 21, 2002, the District Court granted leave for plaintiffs to file a third amended class action petition substituting in new class representative plaintiffs thereby changing the style of the case to Will Price, Stixon Petroleum, Inc. and Thomas F. Boles on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, Kansas. The petition alleges that the defendants engaged in the mismeasurement of volumes and wrongful analysis of heating content of natural gas and engaged in other activities which resulted in the underpayment of revenue owed to working interest owners, royalty interest owners, overriding royalty interest owners and state taxing authorities. If successful, this litigation could result in a decrease in royalty income received by the Trust. At this time, no estimate can be made as to the amount of any loss in this litigation, or the portion of any such potential loss that would be allocated to the Trust. Any proposed allocation of loss to the Trust will be reviewed by the Trust’s consultants.

Item 6. Exhibits and Reports on Form 8-K.

(a) Exhibits.

4(a)	Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.
4(b)	Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.
4(c)	Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.

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31	Certification required by Rule 13a-14(a), dated August 13, 2003, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee for the Trust.**
32	Certification required by Rule 13a-14(b), dated August 13, 2003, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the Trust.**

** Filed herewith.

(b)	Reports on Form 8-K.
	The Trust filed a report on Form 8-K on April 24, 2003. In the report, the Trust reported, under Items 9 and 12, that on April 17, 2003, it had issued a press release announcing a monthly cash distribution to Unit Holders.
	The Trust filed a report on Form 8-K on June 26, 2003. In the report, the Trust reported, under Items 9 and 12, that on June 20, 2003, it had issued a press release announcing a monthly cash distribution to Unit Holders.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

TEXASBANK, AS TRUSTEE FOR THE SAN JUAN BASIN ROYALTY TRUST
By	/s/ Lee Ann Anderson      Lee Ann Anderson      Vice President and Trust Officer

Date: August 13, 2003

(The Trust has no directors or executive officers.)

INDEX TO EXHIBITS

		Sequentially
Exhibit		Numbered
Number	Exhibit	Page
4(a)	Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.
4(b)	Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust’s Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.
4(c)	Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.
31	Certification required by Rule 13a-14(a), dated August 13, 2003, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee for the Trust.**
32	Certification required by Rule 13a-14(b), dated August 13, 2003, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the Trust.**

** Filed herewith