SAN JUAN BASIN ROYALTY TRUST - Quarter Report: 2005 September (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended September 30, 2005

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

For the transition period from                      to                     

SAN JUAN BASIN ROYALTY TRUST

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

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

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

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

N/A
(Former name, former address and former fiscal year, if changed since last report)

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

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

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

Number of Units of beneficial interest outstanding at November 8, 2005: 46,608,796

SAN JUAN BASIN ROYALTY TRUST

PART I

Item 1. Financial Statements.

     The condensed financial statements included herein have been prepared 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 financial statements of the San Juan Basin Royalty Trust (the “Trust”) continue to be prepared in a manner that differs from accounting principles generally accepted in the United States of America (“GAAP”); this form of 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 Exchange Act of 1934, although TexasBank, the Trustee of the Trust, 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 for the year ended December 31, 2004. In the opinion of the Trustee, all adjustments, consisting only of normal recurring adjustments, have been included that are necessary to present fairly the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust at September 30, 2005, and the distributable income and changes in trust corpus for the three-month periods and nine-month periods ended September 30, 2005 and 2004. The distributable income for such interim periods is not necessarily indicative of the distributable income for the full year.

SAN JUAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS

		September 30,				December 31,
		2005				2004
		(Unaudited)
ASSETS
Cash and short-term investments		$	9,260,904			$	10,140,045
Net overriding royalty interest in producing oil and gas properties (net of accumulated amortization of $108,717,540 and $106,600,707 at September 30, 2005 and December 31, 2004, respectively)			24,557,988				26,674,821
		$	33,818,892			$	36,814,866
LIABILITIES AND TRUST CORPUS
Distribution payable to Unit Holders		$	9,146,046			$	10,025,187
Cash reserves			114,858				114,858
Trust corpus – 46,608,796 Units of beneficial interest authorized and outstanding			24,557,988				26,674,821
		$	33,818,892			$	36,814,866

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Royalty income		$	32,832,885			$	34,673,819			$	107,370,970			$	81,379,357
Interest income			44,893				18,478				110,249				38,992
			32,877,778				34,692,297				107,481,219				81,418,349
General and administrative expenditures			585,828				290,676				1,933,994				1,333,044
Distributable income		$	32,291,950			$	34,401,621			$	105,547,225			$	80,085,305
Distributable income per Unit (46,608,796 Units)		$	.692829			$	.738093			$	2.264533			$	1.718245

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

SAN JUAN BASIN ROYALTY TRUST

CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Trust corpus, beginning of period		$	25,197,903			$	28,338,910			$	26,674,821			$	29,822,820
Amortization of net overriding royalty interest			(639,915	)			(850,220	)			(2,116,833	)			(2,334,130	)
Distributable income			32,291,950				34,401,621				105,547,225				80,085,305
Distributions declared			(32,291,950	)			(34,401,621	)			(105,547,225	)			(80,085,305	)
Trust corpus, end of period		$	24,557,988			$	27,488,690			$	24,557,988			$	27,488,690

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

SAN JUAN BASIN ROYALTY TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

1.

BASIS OF ACCOUNTING

The San Juan Basin Royalty Trust (the “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 with respect to the Trust’s 75% net overriding royalty interest (the “Royalty”) in certain oil and gas leasehold and royalty interests (the “Underlying Properties”) by Burlington Resources Oil & Gas Company LP (“BROG”), the present owner of the Underlying Properties, to the Trustee for the Trust. Royalty income consists of the proceeds received by BROG from the sale of production from the Underlying Properties less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty income paid to the Trust and the distribution to Unit Holders for that month.
	•		Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty income for liabilities and contingencies.
	•		Distributions to Unit Holders are recorded when declared by the Trustee.
	•		The conveyance which transferred the Royalty to the Trust provides that any excess of development and production costs applicable to the Underlying Properties over gross proceeds from such properties must be recovered from future net proceeds before Royalty income is again paid to the Trust.

The financial statements of the Trust differ from financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on 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.

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 such tax treatment.

Sales of gas production from coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits under Section 29 of the Internal Revenue Code of 1986, as amended, through 2002, but not thereafter. Accordingly, under present law, the Trust’s production of gas from coal seam wells does not qualify for the Section 29 tax credit. Congress has at various times since 2002 considered energy legislation, including provisions to reinstate the Section 29 credit in various ways and to various extents, but no legislation that would qualify the Trust’s current production for such credit has been enacted. Most recently, for example, on August 8, 2005, new energy tax legislation was enacted which, among other things, modifies the Section 29 credit in several respects, but does not extend the credit for production from coal seam wells. No prediction can be made as to what future tax legislation affecting Section 29 may be proposed or enacted or, if enacted, its impact, if any, on the Trust and the Unit Holders.

The classification of the Trust’s income for purposes of the passive loss rules may be important to a Unit Holder. As a result of the Tax Reform Act of 1986, royalty income such as that derived through the Trust will generally be treated as portfolio income and will not reduce passive losses.

3.

CONTINGENCIES

See Part II, Item 1, “Legal Proceedings” concerning the status of litigation matters.

4.

SETTLEMENTS

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 has been addressed by a combination of volume adjustments and a $243,968 increase in revenue included in net proceeds paid to the Trust by BROG in July 2004.

During 2004, commencing in July of that year, an aggregate of $3,314,808 was included in calculating net proceeds paid to the Trust by BROG as part of the ongoing negotiation of joint interest audit exceptions, interest for resolved audit exceptions, and insurance proceeds for a business interruption claim.

In March 2005, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, $833,851 was included in calculating net proceeds paid to the Trust by BROG in settlement of claims for interest on late payments of net proceeds and in settlement of certain other audit issues. Of that amount, $822,077 was included in settlement of claims for additional revenue and $11,774 was included in settlement of claims concerning disputed lease operating expenses.

In May 2005, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, $988,392 was included in calculating net proceeds paid to the Trust by BROG in settlement of certain of those issues. Of that amount, $982,038 was included in net proceeds paid to the Trust by BROG in settlement of claims for additional revenue and $6,354 was included in net proceeds in settlement of claims concerning disputed lease operating expenses.

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

Forward-Looking Information

     Certain information included in this Quarterly Report on Form 10-Q 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, estimated future net revenues, estimates of reserves, the results of the Trust’s activities, and regulatory matters. Such forward-looking statements generally are accompanied by words such as “may,” “will,” “estimate,” “expect,” “predict,” “project,” “anticipate,” “goal,” “should,” “assume,” “believe,” “plan,” “intend,” or other words that convey the uncertainty of future events or outcomes. Such statements reflect BROG’s current view with respect to future events; are based on an assessment of, and are subject to, a variety of factors deemed relevant by TexasBank, the Trustee of the Trust, and BROG and involve risks and uncertainties. These risks and uncertainties include volatility of oil and gas prices, product supply and demand, competition, regulation or government action, litigation and uncertainties about estimates of reserves. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated.

Principal Trust Risk Factors

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

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

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

	•		political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;
	•		worldwide economic conditions;
	•		weather conditions;
	•		the supply and price of foreign oil and gas;
	•		the level of consumer demand;
	•		the price and availability of alternative fuels;
	•		the proximity to, and capacity of, transportation facilities; and
	•		the effect of worldwide energy conservation measures.

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

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

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

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

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

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

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

	•		historical production from the area compared with production rates from similar producing areas;
	•		the assumed effect of governmental regulation; and
	•		assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures.

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

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

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

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

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

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

     Neither the Trustee nor the Unit Holders can influence or control the operation or future development of the Underlying Properties. The Underlying Properties are owned by BROG and BROG operates the majority of such properties and handles the calculation of the net proceeds attributable to the Royalty and the payment of Royalty income to the Trust.

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

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

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

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

     Unit Holders have limited voting rights.

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

Business Overview

     The Trust is an express trust created under the laws of the state of Texas by the San Juan Basin Royalty Trust Indenture (the “Original Indenture”) entered into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and The Fort Worth National Bank. Effective as of September 30, 2002, the Original Indenture was amended and restated (the Original Indenture, as amended and restated, the “Indenture”). The Trustee of the Trust is TexasBank. On September 19, 2005, Compass Bancshares Inc. (“Compass”) announced the signing of a definitive agreement to acquire TexasBanc Holding Co. (“TexasBanc”), the parent company of the Trustee, in a combination that would create the fifth largest bank in Texas. Upon completion of the transaction, with combined total assets of approximately $31.1 billion and a market capitalization of $6.1 billion, Compass will rank as the 28th largest U.S. bank holding company, with operations in Texas, New Mexico, Florida, Colorado, Arizona and Alabama. The transaction, which is anticipated to be completed in January 2006, is subject to all required regulatory approvals, approval by TexasBanc shareholders and other customary conditions.

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

     The Royalty constitutes the principal asset of the Trust and the beneficial interests in the Trust are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Holders of Units are referred to herein as “Unit Holders.” Subsequent to the Conveyance of the Royalty, through a series of assignments and mergers, Southland Royalty’s successor became BROG.

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

Three Months Ended September 30, 2005 and 2004

     The Trust received Royalty income of $32,832,885 and interest income of $44,893 during the third quarter of 2005. There was no change in cash reserves. After deducting administrative expenses of $585,828, distributable income for the quarter was $32,291,950 ($.692829 per Unit). In the third quarter of 2004, royalty income was $34,673,819, interest income was $18,478, there was no change in cash reserves, administrative expenses were $290,676 and distributable income was $34,401,621 ($.738093 per Unit). Based on 46,608,796 Units outstanding, the per Unit distributions during the third quarter of 2005 were as follows:

July		$	.279524
August			.217075
September			.196230
Quarter Total		$	.692829

     The Royalty income distributed in the third quarter of 2005 was lower than that distributed in the third quarter of 2004 primarily due to increased production costs and slightly decreased production volumes. In calculating the September 2005 distribution, BROG reduced volumes used in calculating the Royalty payable to the Trust due to accrual adjustments for February and March production. The primary reasons for reduced production for those months were weather-related shut-downs and unscheduled pipeline maintenance. The average gas price increased from $5.25 per Mcf for the third quarter of 2004 to $5.85 per Mcf for the third quarter of 2005. In addition, in July 2004, BROG included an aggregate of $1,835,500 in calculating the Trust’s July 2004 royalty income payment. This represented the Trust’s 75% interest in settlement of certain joint interest audit issues, including claims related to natural gas liquids, gas imbalances and interest on other settled claims. Also, in July 2004, BROG adjusted the capital expenditures accrued for the properties to which the Royalty relates by approximately $1 million, resulting in a corresponding increase in the Royalty income received by the Trust in July 2004. Interest earnings for the quarter ended September 30, 2005, as compared to the quarter ended September 30, 2004, were higher, primarily due to an increase in funds available for investment pending distribution as well as an increase in interest rates. Administrative expenses were higher primarily as a result of differences in timing in the receipt and payment of these expenses, but also as a result of complying with the new internal control over financial reporting and other requirements of the Sarbanes-Oxley Act of 2002 and costs incurred in resolving certain outstanding audit issues.

     BROG has informed the Trustee that the New Mexico Oil and Gas Proceeds Withholding Tax Act (the “Withholding Tax Act”) requires remitters who pay certain oil and gas proceeds from production on New Mexico properties on or after October 1, 2003, to withhold income taxes from such proceeds in the case of certain nonresident recipients. The Trustee, on advice of New Mexico counsel, has observed that “net profits interests,” such as the Royalty, and other types of interests, the extent of which cannot be determined with respect to a specific share of the oil and gas production, are excluded from the withholding requirements of the Withholding Tax Act. Unit Holders are reminded to consult with their tax advisors regarding the applicability of New Mexico income tax to distributions received from the Trust by a Unit Holder.

     The capital costs attributable to the Underlying Properties for the third quarter of 2005 and deducted by BROG in calculating Royalty income were approximately $5.7 million. BROG’s capital expenditure budget for the Underlying Properties for 2005 is estimated at $17 million of which approximately $9.1 million has been spent as of September 30, 2005; however, 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 2005 could range from $15 million to $25 million. Capital expenditures were approximately $3.5 million for the third quarter of 2004. In 2004, approximately $22.3 million in capital expenditures were deducted in calculating Royalty income. In February 2005, BROG informed the Trustee that the 2005 budget for the Underlying Properties anticipates 401 projects, including the drilling of 71 new wells to be operated by BROG and 31 wells to be operated by third parties. Of the new BROG operated wells, 19 are projected to be conventional wells completed in the Pictured Cliffs, Mesaverde and/or Dakota formations, and the remaining 52 are projected as coal seam wells completed in the Fruitland Coal formation. A total of 21 of the wells operated by third parties are projected to be conventional wells and the remaining ten are projected to be coal seam wells. BROG projects approximately $12 million to be spent on the new wells, and $5 million is to be expended in working over existing wells and in the maintenance and improvement of production facilities. BROG has announced that the budget for 2005 reflects the commencement of a shift toward increased development of conventional gas, including infill drilling to the Mesaverde and Dakota formations, and a winding down of its program for infill drilling in the Fruitland Coal formation.

     BROG has informed the Trust that lease operating expenses and property taxes were $6,115,517 and $184,056, respectively, for the third quarter of 2005, as compared to $4,644,449 and $195,518, respectively, for the third quarter of 2004.

     BROG has reported to the Trustee that during the third quarter of 2005, seven gross (1.09 net) coal seam wells, one gross (0.88 net) coal seam recavitation, two gross (0.61 net) coal seam recompletions, and 17 gross (3.20 net) conventional wells were completed on the Underlying Properties.

     Sixty-five gross (7.28 net) coal seam wells, two gross (0.86 net) coal seam recompletions, 55 gross (9.71 net) conventional wells, 11 gross (1.74 net) payadds, three gross (0.92 net) recompletions, and five gross (3.11 net) restimulations were in progress at September 30, 2005.

     There were three gross (0.005 net) conventional wells, seven gross (5.59 net) recompletions, one gross (0.88 net) restimulation, eight gross (2.72 net) coal seam wells, one gross (0.87 net) coal seam recompletion, and one gross (0.007 net) miscellaneous coal seam project completed on the Underlying Properties as of September 30, 2004. Thirty-four gross (5.75 net) conventional wells, seven gross (3.12 net) recompletions, three gross (2.24 net) restimulations, five gross (1.73 net) payadds, 77 gross (7.68 net) coal seam wells, five gross (2.74 net) coal seam recompletions, and one gross (0.06 net) miscellaneous coal seam project were in progress at September 30, 2004.

     “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.

     Royalty income for the quarter ended September 30, 2005 is associated with actual gas and oil production during May 2005 through July 2005 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the three months ended September 30, 2005 and 2004 were as follows:

		Three Months Ended
		September 30,
		2005				2004
Gas:
Total sales (Mcf)			10,466,804				10,859,313
Mcf per day			113,770				118,036
Average price (per Mcf)		$	5.85			$	5.25
Oil:
Total sales (Bbls)			17,020				21,091
Bbls per day			185				229
Average price (per Bbl)		$	49.70			$	35.53

Gas and oil sales attributable to the Royalty for the quarters ended September 30, 2005 and 2004 were as follows:

		Three Months Ended
		September 30,
		2005				2004
Gas sales (Mcf)			6,163,750				6,859,527
Oil sales (Bbls)			10,017				13,296

     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 third quarter of 2005, average gas prices were $.60 higher than the average prices reported during the third quarter of 2004. The average price per barrel of oil during the third quarter of 2005 was $14.17 per barrel higher than that received for the third quarter of 2004 due to increases in oil prices in world markets generally, including the posted prices applicable to oil sales attributable to the Royalty.

     BROG previously entered into two contracts for the sale of all volumes of gas produced from the Underlying Properties. These contracts provided for (i) the sale of such gas to Duke Energy and Marketing, L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year-to-year thereafter until terminated by either party on twelve months notice, and (iii) the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of New Mexico. Effective January 1, 2004, the rights and obligations of Duke Energy and Marketing L.L.C. were assumed by ConocoPhillips Company (“ConocoPhillips”) pursuant to an Assignment and Novation Agreement. By correspondence dated March 25, 2004, BROG notified ConocoPhillips of BROG’s election to terminate such contract as of March 31, 2005. BROG then prepared a form of request for proposal and circulated it to a number of potential purchasers, including ConocoPhillips, inviting them to bid for the purchase of the gas currently sold under the contract expiring March 31, 2005. Effective as of April 1, 2005, BROG entered into two new contracts for the sale of all volumes of gas produced from the Underlying Properties and formerly sold to ConocoPhillips. These new contracts provide for (i) the sale of such gas to ChevronTexaco Natural Gas, a division of Chevron U.S.A. Inc., and Coral Energy Resources, L.P., respectively, (ii) the delivery of such gas at various delivery points through March 31, 2007, and from year-to-year thereafter until terminated by either party on twelve months notice, and (iii) the sale of such gas at prices which fluctuate in accordance with the published indices for gas sold in the San Juan Basin of New Mexico. With respect to BROG’s contract with PNM Gas Services, BROG and PNM Gas Services have entered into a letter agreement dated January 31, 2005, pursuant to which the parties waive the right to terminate the underlying contract as of March 31, 2006, so that the term of that contract will continue until at least March 31, 2007, and from year-to-year thereafter until terminated by either party upon twelve months notice to the other. Unit Holders are referred to Note 6 of the Notes to Financial Statements in the Trust’s 2004 Annual Report for further information concerning the marketing of gas produced from the Underlying Properties.

     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.

Nine Months Ended September 30, 2005 and 2004

     For the nine months ended September 30, 2005, the Trust received Royalty income of $107,370,970 and interest income of $110,249. There was no change in cash reserves. After deducting administrative expenses of $1,933,994, distributable income was $105,547,225 ($2.264533 per Unit) for the nine months ended September 30, 2005. For the nine months ended September 30, 2004, the Trust received Royalty income of $81,379,357 and interest income of $38,992. There was no change in cash reserves. After deducting administrative expenses of $1,333,044, distributable income was $80,085,305 ($1.718245 per Unit) for the nine months ended September 30, 2004.

     The increase in distributable income from 2004 to 2005 resulted primarily from higher gas prices during the first nine months of 2005. Interest earnings for the nine months ended September 30, 2005, as compared to the nine months ended September 30, 2004 were higher primarily due to an increase in funds

available for investment pending distribution as well as an increase in interest rates. General and administrative expenses were higher for the nine months ended September 30, 2005, as compared to the same period in 2004 primarily as a result of differences in timing in the receipt and payment of these expenses, but also as a result of complying with the new internal control over financial reporting and other requirements of the Sarbanes-Oxley Act of 2002 and costs incurred in resolving certain outstanding joint interest audit issues.

     Capital expenditures incurred by BROG, attributable to the Underlying Properties, for the first nine months of 2005 amounted to approximately $14.4 million. Capital expenditures were approximately $17.5 million for the first nine months of 2004. Lease operating expenses and property taxes totaled $15,809,068 and $499,498, respectively, for the first nine months of 2005 as compared to $13,258,390 and $445,018, respectively, for the first nine months of 2004.

     BROG has reported to the Trustee that during the nine months ended September 30, 2005, 28 gross (0.41 net) conventional wells, two gross (0.004 net) payadds, 12 gross (2.50 net) coal seam wells, one gross (0.88 net) coal seam recavitation, two gross (0.61 net) coal seam recompletions, and five gross (0.20 net) miscellaneous coal seam capital projects were completed on the Underlying Properties.

     There were 21 gross (6.39 net) conventional wells, three gross (0.007 net) payadds, eight gross (6.03 net) recompletions, nine gross (5.95 net) restimulations, 34 gross (5.20 net) coal seam wells, two gross (1.69 net) coal seam recompletions and two gross (0.05 net) miscellaneous coal seam capital projects completed on the Underlying Properties during the nine months ended September 30, 2004.

     Royalty income for the nine months ended September 30, 2005 is associated with actual gas and oil production during November 2004 through July 2005 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the nine months ended September 30, 2005 and 2004 were as follows:

		Nine Months Ended
		September 30,
		2005				2004
Gas:
Total sales (Mcf)			32,618,591				32,720,033
Mcf per day			119,482				119,416
Average price (per Mcf)		$	5.77			$	4.60
Oil:
Total Sales (Bbls)			53,081				59,655
Bbls per day			194				218
Average price (per Bbl)		$	46.68			$	32.16

Gas and oil sales attributable to the Royalty for the nine months ended September 30, 2005 and 2004 were as follows:

		Nine Months Ended
		September 30,
		2005				2004
Gas sales (Mcf)			20,084,548				18,758,186
Oil sales (Bbls)			32,713				34,609

     During the first nine months of 2005, gas and oil prices were higher than during the first nine months of 2004. 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.

Calculation of Royalty Income

     Royalty income received by the Trust for the three months and nine months ended September 30, 2005 and 2004, respectively, was computed as shown in the following table:

		Three Months Ended								Nine Months Ended
		September 30,								September 30,
		2005				2004				2005				2004
Gross proceeds of sales from the Underlying Properties:
Gas proceeds		$	61,276,528			$	56,977,514			$	188,240,413			$	150,416,797
Oil proceeds			845,878				749,444				2,478,003				1,918,288
Other			—				2,447,333	(1)			2,405,486	(2)(3)			2,447,333	(1)
Total			62,122,406				60,174,291				193,123,902				154,782,418
Less production costs:
Severance tax – gas			6,296,781				5,571,441				18,964,311				14,838,895
Severance tax – oil			87,509				75,507				254,395				196,443
Lease operating expense and property tax			6,299,573				4,839,967				16,308,566	(2)(3)			13,703,408
Other			—				—				42,505				42,763
Capital expenditures			5,661,363				3,455,618	(4)			14,392,832				17,495,100	(4)
Total			18,345,226				13,942,533				49,962,609				46,276,609
Less excess production costs and interest from prior year			—				—				—				—
Net profits			43,777,180				46,231,758				143,161,293				108,505,809
Net overriding royalty interest			75	%			75	%			75	%			75	%
Royalty income		$	32,832,885			$	34,673,819			$	107,370,970			$	81,379,357

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).

Effects of Securities Regulation

     As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is and will continue to be subject to extensive regulation under, among others, the Securities Act of 1933, the Securities Exchange Act of 1934 (which contains many of the provisions of the Sarbanes-Oxley Act of 2002) and the rules and regulations of the NYSE. Issuers failing to comply with such authorities risk serious consequences, including criminal as well as civil and administrative penalties. In most instances, these laws, rules and regulations do not specifically address their applicability to publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act of 2002 provides for the adoption by the Securities and Exchange Commission (the “Commission”) and NYSE of certain rules and regulations that may be impossible for the Trust to literally satisfy because of its nature as a pass-through trust. It is the Trustee’s intention to follow the Commission’s and NYSE’s rulemaking closely, attempt to comply with such rules and regulations and, where appropriate, request relief from these rules and regulations. However, if the Trust is unable to comply with such rules and regulations or to obtain appropriate relief, the Trust may be required to expend as yet unknown but potentially material costs to amend the Indenture that governs the Trust to allow for compliance with such rules and regulations. To date, the rules implementing the Sarbanes-Oxley Act of 2002 have generally made appropriate accommodation for passive entities such as the Trust.

Critical Accounting Policies

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

	•		Royalty income recorded for a month is the amount computed and paid pursuant to the Conveyance by BROG to the Trustee for the Trust. Royalty income consists of the proceeds received by BROG from the sale of production from the Underlying Properties less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty income paid to the Trust and the distribution to Unit Holders for that month.
	•		Trust expenses recorded are based on liabilities paid and cash reserves established from royalty income for liabilities and contingencies.
	•		Distributions to Unit Holders are recorded when declared by the Trustee.

•

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

     The financial statements of the Trust differ from financial statements prepared in accordance with GAAP because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus instead of an expense.

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 is prohibited from engaging in borrowing transactions, other than the Trust’s ability to borrow money periodically as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust. The amount of any such borrowings is unlikely to be material to the Trust. The Trust periodically holds short-term investments acquired with funds held by the Trust pending distribution to Unit Holders and funds held in reserve for the payment of Trust expenses and liabilities. Because of the short-term nature of these borrowings and investments and certain limitations upon the types of such investments which may be held by the Trust, the Trustee believes that the Trust is not subject to any material interest rate risk. The Trust does not engage in transactions in foreign currencies which could expose the Trust or Unit Holders to any foreign currency related market risk. The Trust does not market the gas, oil and/or natural gas liquids from the Underlying Properties. BROG is responsible for such marketing.

Item 4. Controls and Procedures.

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

     The Indenture does not require BROG to update or provide information to the Trust. Under the Conveyance transferring the Royalty to the Trust, BROG is obligated to provide the Trust with certain information concerning calculations of net proceeds owed to the Trust, among other information. Pursuant to the settlement of litigation in 1996 between the Trust and BROG, BROG agreed to new, more formal financial reporting and audit procedures as compared to those provided in the Conveyance.

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

     The Trustee has evaluated the Trust’s disclosure controls and procedures as of September 30, 2005, and has concluded that such disclosure controls and procedures are effective at the “reasonable assurance” level to ensure that material information related to the Trust is gathered on a timely basis to be included in the Trust’s periodic reports. In reaching its conclusion, the Trustee considered the Trust’s dependence on BROG to deliver timely and accurate information to the Trust. The Trustee has not reviewed the Trust’s disclosure controls and procedures in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee.

     During the quarter ended September 30, 2005, there were no changes in the Trust’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Securities Exchange Act of 1934) that materially affected, or are reasonably likely to materially affect, the Trust’s internal control over financial reporting. The Trustee has not evaluated the Trust’s internal control over financial reporting in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Indenture provide for, officers, a board of directors or an independent audit committee.

PART II

Item 1. Legal Proceedings.

     As discussed above under Part I, Item 4 “Controls and Procedures,” 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 Commission. Although the Trustee receives periodic updates from BROG regarding activities which may relate to the Trust, the Trust’s ability to timely report certain information required to be disclosed in the Trust’s periodic reports is dependent on BROG’s timely delivery of the information to the Trust.

     The Trust is not named as a party, nor are its assets subject, to any material pending legal proceedings, however, BROG is involved in various legal proceedings, the outcome of which may impact the Trust. Should certain legal proceedings to which BROG is a party be decided in a manner adverse to BROG, the amount of Royalty income received by the Trust could materially decrease. The Trust has not received from BROG any estimate of the amount of any potential loss in such proceedings, or the portion of any such potential loss that might be allocated to the Royalty.

Item 6. 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 to the Trust’s Current Report on Form 8-K filed with the Commission 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 Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
4(c)		Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the

		Trust’s Quarterly Report on Form 10-Q filed with the Commission for the quarter ended September 30, 2002, is incorporated herein by reference.*
31		Certification required by Rule 13a-14(a), dated November 8, 2005, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee of the Trust.**
32		Certification required by Rule 13a-14(b), dated November 8, 2005, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the Trust.***

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.

Date: November 8, 2005

(The Trust has no directors or executive officers.)

INDEX TO EXHIBITS

Exhibit
Number		Description
4(a)		Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 to the Trust’s Current Report on Form 8-K filed with the Commission 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 Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
4(c)		Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the Commission for the quarter ended September 30, 2002, is incorporated herein by reference.*
31		Certification required by Rule 13a-14(a), dated November 8, 2005, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, the Trustee of the Trust.**
32		Certification required by Rule 13a-14(b), dated November 8, 2005, by Lee Ann Anderson, Vice President and Trust Officer of TexasBank, on behalf of TexasBank, the Trustee of the Trust.***