SAN JUAN BASIN ROYALTY TRUST - Quarter Report: 2004 June (Form 10-Q)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10-Q

For the Quarterly Period Ended June 30, 2004
or

For the transition period from                     to                    

Commission File No. 1-8032

SAN JUAN BASIN ROYALTY TRUST

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 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

Number of Units of beneficial interest outstanding at August 9, 2004: 46,608,796

Table of Contents

SAN JUAN BASIN ROYALTY TRUST

PART I
FINANCIAL INFORMATION

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, 2003. 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 June 30, 2004, and the distributable income and changes in trust corpus for the three-month periods and six-month periods ended June 30, 2004 and 2003. 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

CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

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)

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 (the “Trust”) was established as of November 1, 1980. The financial statements of the Trust are prepared on the following basis:

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 that 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.

2. FEDERAL INCOME TAXES

For federal income tax purposes, the Trust constitutes a fixed investment trust that 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 production from coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits through 2002. Although both houses of Congress are presently considering energy legislation, including provisions to extend or reinstate the Section 29 credit in various ways,

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whether such provisions will be enacted into law, and if so, the effect thereof on the Trust and the Unit Holders is at present unknown. Even though the Section 29 credit does not apply to qualified fuel sold in 2003 or later, a Section 29 credit (at the rate applicable in 2002) may apply to proceeds received in 2003 or later for qualified fuel sold in 2002 and earlier years for Unit Holders that utilize the cash method of tax accounting. The Internal Revenue Service has issued Rev. Proc. 2004-27 to the effect that cash method taxpayers may claim the Section 29 credit in a later year for sales of qualified fuel in 2002 and earlier years where the proceeds from such sales are received in the later year.

To benefit from the credit in 2004, each cash basis Unit Holder must determine from the tax information the Unit Holder received from the Trust, its pro rata share of qualifying production of the Trust sold before January 1, 2003, based upon the number of Units owned during each month of the year, and the amount of available credit per MMbtu for the year, and then apply the tax credit against the Unit Holder’s own income tax liability, but such credit could not reduce the Unit Holder’s regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below its tentative minimum tax. Section 29 also provides that any amount of Section 29 credit disallowed for the tax year solely because of this limitation will increase a taxpayer’s credit for prior year minimum tax liability, which may be carried forward indefinitely as a credit against the taxpayer’s regular tax liability, subject, however, to the limitations described in the preceding sentence. There is no provision for the carryback or carryforward of the Section 29 credit in any other circumstance.

BROG has historically provided to the Trust summary Section 29 tax credit information related to Trust properties. In 1999, the U.S. Court of Appeals for the 10th Circuit upheld the position of the Internal Revenue Service and the Tax Credit that nonconventional fuel such as coal seam gas does not qualify for the Section 29 credit unless the producer has received an appropriate well category determination from the Federal Energy Regulatory Commission. Substantially all of the wells burdened by the Royalty have received the appropriate well category certification. BROG has informed the Trustee that it will continue to seek certification of any qualified but not certified wells burdened by the Royalty.

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. 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 has been addressed by a $243,968 increase in revenue allocated by BROG to the Trust in July 2004, which amount is included in the $1,835,500 referenced in Note 6 below.

5. MMS SETTLEMENT

As part of a settlement between BROG and the Mineral Management Service of the United States Department of the Interior relating to the property from which the Trust’s Royalty was carved, $901,776 (the Trust’s 75% interest of the total settlement) was deducted by BROG in calculating the Trust’s April 2003 Royalty payment. The Trust is in communication with BROG as to the appropriateness of this allocation.

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6. SUBSEQUENT EVENTS

In July 2004, an aggregate of $1,835,500 was included by BROG in calculating the Trust’s July 2004 Royalty payment. This represents the Trust’s 75% interest in the 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.

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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 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 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 an 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.

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 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 in properties located in the San Juan Basin of northwestern New Mexico (the “Underlying Properties”). 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 Royalty are divided into that number of units of beneficial interest (the “Units”) of the Trust equal to the number of shares of the common 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 June 30, 2004 and 2003

     The Trust received Royalty income of $25,509,188 and interest income of $11,822 during the second quarter of 2004. There was no change in cash reserves. After deducting administrative expenses of $529,205, distributable income for the quarter was $24,991,805 ($.536204 per Unit). In the second quarter of 2003, royalty income was $26,051,389, interest income was $15,801, there was no change in cash

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reserves, administrative expenses were $448,456 and distributable income was $25,618,734 ($.549655 per Unit). The tax credit relating to production from coal seam and tight sand wells sold before January 1, 2003, totaled approximately $.03 per Unit for the second quarter of 2003. For further information concerning this tax credit, Unit Holders should refer to the Trust’s Annual Report for 2003. Based on 46,608,796 Units outstanding, the per Unit distributions during the second quarter of 2004 were as follows:

     The Royalty income distributed in the second quarter of 2004 was lower than that distributed in the second quarter of 2003 primarily due to increased capital expenditures and production costs. Interest earnings for the quarter ended June 30, 2004, as compared to the quarter ended June 30, 2003, were lower, primarily due to a decrease in funds available for investment and slightly lower interest rates. Administrative expenses were higher primarily as a result of differences in timing in the receipt and payment of these expenses.

     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 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 second quarter of 2004 were reported by BROG as approximately $4.6 million. BROG’s capital expenditure budget for the Underlying Properties for 2004 is estimated at $18.5 million of which approximately $3.3 million has been spent as of June 30, 2004; however, BROG reports that based on its actual capital requirements, its mix of projects and changes in the price of natural gas, the actual capital expenditures for 2004 could range from $15 million to $25 million. Capital expenditures were approximately $2.9 million for the second quarter of 2003. In 2003, approximately $20.6 million in capital expenditures were deducted in calculating Royalty income. In February 2004, BROG informed the Trustee that for 2004 it anticipates 441 projects, including the drilling of 103 new wells to be operated by BROG and 29 wells to be operated by third parties. Of the new BROG operated wells, 30 are projected to be conventional wells completed in the Pictured Cliffs, Mesaverde and/or Dakota formations, and the remaining 73 are projected as coal seam wells completed in the Fruitland Coal formation. A total of 22 of the wells operated by third parties are projected to be conventional wells, and the remaining seven are projected to be coal seam wells. BROG projects approximately $11.7 million to be spent on the new wells, and $6.8 million to be expended in working over existing wells and in the maintenance and improvement of production facilities. BROG has indicated that, principally as a result of the New Mexico Oil Conservation Division’s approval of reduced, 160-acre spacing in the Fruitland Coal formation, BROG’s budget for 2004 reflects a continued focus on that formation.

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

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Properties is relatively low, but many of the recompletions and restimulations are scheduled on properties in which such working interest is relatively high.

     BROG has informed the Trust that lease operating expenses and property taxes were $4,615,886 and $122,700 respectively, for the second quarter of 2004, as compared to $3,902,841 and $135,000, respectively, for the second quarter of 2003.

     BROG has reported to the Trustee that during the second quarter of 2004, 21 gross (2.31 net) coal seam wells, one gross (.04 net) miscellaneous coal seam project, eight gross (0.05 net) conventional wells and four gross (1.70 net) restimulations were completed on the Underlying Properties.

     Sixty-three gross (8.89 net) coal seam wells, four gross (1.89 net) recompletions, two gross (.08 net) miscellaneous coal seam projects, 29 gross (5.40 net) conventional wells, four gross (1.72 net) payadds, 11 gross (6.96 net) recompletions and four gross (3.11 net) restimulations were in progress at June 30, 2004.

     There were five gross (2.54 net) conventional wells, 19 gross (0.81 net) payadds, 13 gross (9.54 net) restimulations and eight gross (2.50 net) coal seam wells completed on the Underlying Properties as of June 30, 2003. 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) coals seam wells, one gross (.002 net) recavitation and five gross (.17 net) recompletions were in progress at June 30, 2003.

     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.

     “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 June 30, 2004 is associated with actual gas and oil production during February 2004 through April 2004 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the three months ended June 30, 2004 and 2003 were as follows:

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Gas and oil sales attributable to the Royalty for the quarters ended June 30, 2004 and 2003 were as follows:

     Sales volumes attributable to the Royalty are determined by dividing the net profits received by the Trust and attributable to oil and gas, respectively, by the prices received for sales volumes from the Underlying Properties, taking into consideration production taxes attributable to the Underlying Properties. Since the oil and gas sales attributable to the Royalty are based on an allocation formula 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 2004, average gas prices were $.10 lower than the average prices reported during the second quarter of 2003. The average price per barrel of oil during the second quarter of 2004 was $3.81 per barrel higher than received for the second quarter of 2003 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 produced from the Underlying Properties. These contracts provide for (i) the sale of such gas to Duke Energy and Marketing, L.L.C. and PNM Gas Services, respectively, (ii) the delivery of such gas at various delivery points through March 31, 2005, and from year-to-year thereafter until terminated by either party on twelve months notice, and (iii) for the sale of such gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of 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 has prepared a form of request for proposal that will be circulated 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. Unit Holders are referred to Note 6 of the Notes to Financial Statements in the Trust’s 2003 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.

Six Months Ended June 30, 2004 and 2003

     For the six months ended June 30, 2004, the Trust received Royalty income of $46,705,539 and interest income of $20,514. There was no change in cash reserves. After deducting administrative expenses of $1,042,368, distributable income was $45,683,685 ($.980152 per unit) for the six months ended June 30, 2004. For the six months ended June 30, 2003, the Trust received Royalty income of $45,962,457 and interest income of $23,254. There was no change in cash reserves. After deducting administrative expenses of $868,829, distributable income was $45,116,882 ($.967992 per unit) for the six months ended June 30, 2003.

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     The increase in distributable income from 2003 to 2004 resulted primarily from higher gas prices during the first half of 2004. Interest earnings for the six months ended June 30, 2004, as compared to the six months ended June 30, 2003 were lower primarily due to the timing of receipt of interest income. General and administrative expenses were higher for the six months ended June 30, 2004, as compared to the same period in 2003 primarily due to an initiative to resolve certain outstanding joint interest audit issues with BROG and to differences in timing of the receipt and payment of these expenses.

     Capital expenditures incurred by BROG, attributable to the Underlying Properties, for the first six months of 2004 amounted to approximately $14.0 million. Capital expenditures were approximately $9.4 million for the first six months of 2003. Lease operating expenses and property taxes totaled $8,613,941 and $249,500, respectively, for the first six months of 2004 as compared to $7,824,408 and $271,250, respectively, for the first six months of 2003.

     BROG has reported to the Trustee that during the six months ended June 30, 2004, 18 gross (6.38 net) conventional wells, three gross (0.007 net) payadds, one gross (0.44 net) recompletion, eight gross (5.07 net) restimulations, 26 gross (2.48 net) coal seam wells, one gross (0.82 net) coal seam recompletion and one gross (0.04 net) miscellaneous coal seam capital project were completed on the Underlying Properties.

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

     Royalty income for the six months ended June 30, 2004 is associated with actual gas and oil production during November 2003 through April 2004 from the Underlying Properties. Gas and oil sales from the Underlying Properties for the six months ended June 30, 2004 and 2003 were as follows:

Gas and oil sales attributable to the Royalty for the six months ended June 30, 2004 and 2003 were as follows:

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     During the first six months of 2004, gas and oil prices were higher than during the first six months of 2003. 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 six months ended June 30, 2004 and 2003, respectively, was computed as shown in the following table:

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).

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Effects of Securities Regulation

     As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is and will continue to be subject to extensive regulation under, among others, the Securities Act of 1933, the Securities Exchange Act of 1934, the rules and regulations of the NYSE and the Sarbanes-Oxley Act of 2002. Issuers failing to comply with such authorities risk serious consequences, including criminal as well as civil and administrative penalties. In most instances, these laws, rules and regulations do not specifically address their applicability to publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act of 2002 provides for the adoption by the 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. For example, the Commission is required to adopt rules and regulations pursuant to the Sarbanes-Oxley Act of 2002 that would require a publicly-traded company’s board of directors, audit committee or executive directors (or similar body) to act with respect to certain corporate governance matters. The Trust does not have, nor does the Indenture governing the Trust provide for, a board of directors, an audit committee or any executive officers. Accordingly, the Trust could not literally comply with such rules and regulations. It is the Trustee’s intention to follow the Commission’s and NYSE’s rulemaking closely, attempt to comply with such rules and regulations and, where appropriate, request relief from these rules and regulations. However, if the Trust is unable to comply with such rules and regulations or to obtain appropriate relief, the Trust may be required to expend as yet unknown but potentially material costs to amend the Indenture that governs the Trust to allow for compliance with such rules and regulations.

     During 2003, the Commission adopted rules implementing legislation concerning governance matters for publicly-held entities that was passed as part of the Sarbanes-Oxley Act of 2002. In addition, the NYSE adopted additional corporate governance rules. Not all of the governance requirements are applicable to passive entities such as the Trust.

Critical Accounting Policies

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

     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.

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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 permitted 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 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 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 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 Commission.

     The Trustee has evaluated the Trust’s disclosure controls and procedures as of June 30, 2004, 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 provide for, officers, a board of directors or an independent audit committee.

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     During the quarter ended June 30, 2004, 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.

PART II
OTHER INFORMATION

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 aware of any material developments in, or the termination of, any of the legal proceedings disclosed under Part I, Item 3 of the Trust’s Annual Report on Form 10-K for the year ended December 31, 2003, filed with the Commission on March 15, 2004 (the “Annual Report”). The Trust is not named as a party, nor are its assets subject, to any legal proceedings including, without limitation, those legal proceedings disclosed in the Annual Report. Should any such legal proceeding 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 and Reports on Form 8-K.

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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.

(The Trust has no directors or executive officers.)

INDEX TO EXHIBITS