Item 1.
Business
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. The principal office of the Trust is located at 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116, Attention: Trust Department (telephone number (866) 809-4553). The Trust maintains a website at www.sjbrt.com. The Trust makes available (free of charge) its annual, quarterly and current reports (and any amendments thereto) filed with the Securities and Exchange Commission (the “SEC”) through its website as soon as reasonably practicable after electronically filing or furnishing such material with or to the SEC.
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 was carved out of and now burdens the Underlying Properties as more particularly described under “Item 2.
Item 2.
Properties
The Royalty conveyed to the Trust was carved out of Southland Royalty’s (now BROG’s) working interests and royalty interests (the “Underlying Properties”) in certain properties situated in the San Juan Basin in northwestern New Mexico. See “Item 1. Business” for information on the conveyance of the Royalty to the Trust. References below to “gross” wells and acres are to the interests of all persons owning interests therein, while references to “net” are to the interests of BROG (from which the Royalty was carved) in such wells and acres.
Unless otherwise indicated, the following information in this Item 2 is based upon data and information furnished to the Trustee by BROG.
Producing Acreage, Wells and Drilling
The Underlying Properties consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico and 4,223 gross (1,240 net) economic wells, including dual completions. Production from conventional gas wells is primarily from the Pictured Cliffs, Mesaverde and Dakota formations. During 1988, Southland Royalty began development of coal seam reserves in the Fruitland Coal formation.
The Royalty conveyed to the Trust is limited to the base of the Dakota formation, which is currently the deepest significant producing formation under acreage affected by the Royalty. Rights to production, if any, from deeper formations are retained by BROG.
In February, 2004, BROG announced an estimated capital budget for the Underlying Properties of approximately $18.5 million. However, BROG advised the Trust that based on its actual capital requirements, its mix of projects and swings in the price of natural gas, the actual capital expenditures for 2004 could range from $15 million to $25 million. BROG’s capital plan for the Underlying Properties for 2004 estimated 441
projects, including the drilling of 103 new wells to be operated by BROG and 29 wells to be operated by third parties. In 2004, BROG actually participated in 364 projects, including 82 new wells operated by BROG and 32 wells operated by third parties. 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 reflected a continued focus on that formation.
The aggregate capital expenditures reported by BROG in calculating net proceeds payable to the Trust for 2004 include approximately $10.8 million attributable to the capital budgets for prior years. This occurs because projects within a given year’s budget may extend into subsequent years, with capital expenditures attributable to those projects used in calculating distributable income to the Trust in those subsequent years. Further, BROG’s accounting period for capital expenditures runs through November 30 of each calendar year, such that capital expenditures incurred in December of each year are actually accounted for as part of the following year’s capital expenditures. In addition, with respect to wells not operated by BROG, BROG’s share of capital expenditures may not actually be paid by it until the year or years after those expenses were incurred by the operator. Capital expenditures of approximately $11.5 million for 2004 budgeted projects were used in calculating net proceeds payable to the Trust in calendar year 2004, and approximately $3.3 million in capital expenditures from the 2004 budget were used in calculating net proceeds payable to the Trust for January and February 2005. Therefore, an additional approximately $3.6 million in capital expenditures for budgeted 2004 projects remains to be spent.
During 2004, in calculating the Royalty Income payable to the Trust, BROG deducted approximately $22.3 million of capital expenditures for projects, including drilling and completion of 25 gross (6.49 net) conventional wells, recompletion of 11 gross (8.05 net) conventional wells, nine gross (5.95 net) restimulations, three gross (0.007 net) conventional payadds, 61 gross (6.10 net) coal seam wells, four gross (3.41 net) coal seam recompletions, and two gross (.05 net) miscellaneous coal seam capital projects and facilities maintenance. A payadd is the completion of an additional productive interval in an existing completed zone in a well.
There were 57 gross (6.94 net) new conventional wells, recompletion of three gross (.89 net) conventional wells, four gross (2.24 net) conventional well restimulations, 13 gross (1.74 net) conventional payadds, 48 gross (4.74 net) coal seam wells, four gross (1.90 net) coal seam recompletions and six gross (.27 net) miscellaneous coal seam capital projects in progress as of December 31, 2004
During 2003, in calculating the Royalty Income payable to the Trust, BROG deducted approximately $20.6 million of capital expenditures for projects, including drilling and completion of 44 gross (15.36 net) conventional wells, recompletion of two gross (.07 net) conventional wells, three gross (.94 net) miscellaneous capital projects, 29 gross (21.55 net) restimulations, 49 gross (3.22 net) conventional payadds, 53 gross (16.98 net) coal seam wells, nine gross (1.6 net) coal seam recompletions, two gross (.92 net) coal seam recavitations, one gross (.04 net) coal seam restimulation, and two gross (.88 net) miscellaneous coal seam capital projects and facilities maintenance. There were 32 gross (7.0 net) new conventional wells, recompletion of 15 gross (3.72 net) conventional wells, 22 gross (9.11 net) conventional well restimulations, 14 gross (3.65 net) conventional payadds, 54 gross (14.43 net) coal seam wells, six gross (1.62 net) coal seam recompletions, one gross (.002 net) recavitation, and six gross (.20 net) miscellaneous coal seam capital projects in progress as of December 31, 2003.
BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2005 is estimated at $17 million. Approximately $12 million of that budget is allocable to new wells, with approximately 61% of those wells, at an aggregate cost of approximately $5.4 million, projected to be drilled to formations producing coal seam gas as distinguished from conventional gas, and $4.9 million is to be expended in working over existing wells and in the maintenance and improvement of production facilities. 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. BROG 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 to the Pictured Cliffs, Mesaverde, and/or Dakota formations, and the remaining 52 are projected as coal seam gas wells to be
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 to be coal seam wells. BROG has announced that the budget for 2005 reflects the commencement of a shift toward increased development of conventional gas and a winding down of its program for infill drilling in the Fruitland Coal formation.
In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In July 2003, the New Mexico Oil Conservation Division approved 160-acre spacing in the Fruitland Coal formation. BROG informed the Trust that, principally as a result of this approval, its budget for 2004 reflected a continued focus on the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.
BROG indicates its budget for 2005 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 2005 are projected to be drilled on certain of the Underlying Properties in which the fractional working interest included in the Underlying Properties is relatively low, but many of the recompletions and restimulations are scheduled on other properties included in the Underlying Properties in which such working interest is relatively high.
Oil and Gas Production
The Trust recognizes production during the month in which the related net proceeds attributable to the Royalty are paid to the Trust. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2004, were as follows:
Pricing Information
Gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under “Regulation” for information as to federal regulation of prices of oil and natural gas. Gas production from the Underlying Properties totaled 44,015,816 Mcf during 2004.
On September 4, 1996, the Trustee announced a settlement of litigation filed by the Trustee against BROG. In the settlement, agreement was reached, among other things, regarding marketing arrangements for the sale of those gas, oil and natural gas liquids products from the Underlying Properties going forward as follows:
(i) BROG agreed that all subsequent contracts for the sale of gas from the Underlying Properties would require the written approval of an independent gas marketing consultant acceptable to the Trust;
(ii) BROG will continue to market the oil and natural gas liquids from the Underlying Properties but will make payments to the Trust based on actual proceeds from such sales, and BROG will no longer use posted prices as the basis for calculating proceeds to the Trust nor make a deduction for marketing fees associated with sales of oil or natural gas liquids products; and
(iii) The independent marketer of the gas from the Underlying Properties is entitled to use of BROG’s current gas transportation, gathering, processing and treating agreements with third parties, at least through the remainder of their primary terms.
See Note 5 of the Notes to Financial Statements in the Trust’s Annual Report to Unit Holders for the year ended December 31, 2004, for further discussion of this settlement and its impact on the Trust.
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) 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 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 PNM Gas Services, neither BROG nor PNM Gas Services notified the other party of its desire to terminate the contract and, accordingly, the PNM Gas Services contract has been extended until March 31, 2006. See Note 6 of the Notes to Financial Statements in the Trust’s 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, 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.
Oil and Gas Reserves
The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Form 10-K:
“Estimated future net revenues” are computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. “Estimated future net revenues” are sometimes referred to in this Form 10-K as “estimated future net cash flows.”
“Present value of estimated future net revenues” is computed using the estimated future net revenues (as defined above) and a discount rate of 10%.
“Proved reserves” are those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions.
“Proved developed reserves” are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
“Proved undeveloped reserves” are those proved reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required.
The independent petroleum engineers’ reports as to the proved oil and gas reserves as of December 31, 2002, 2003 and 2004, were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a
reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2001, to December 31, 2004, (in thousands):
Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2004, 2003 and 2002 were as follows (in thousands):
Generally, the calculation of oil and gas reserves takes into account a comparison of the value of the oil or gas to the cost of producing those minerals, in an attempt to cause minerals in the ground to be included in reserve estimates only to the extent that the anticipated costs of production will be exceeded by the anticipated sales revenue. Accordingly, an increase in sales price and/or a decrease in production cost can itself result in an increase in estimated reserves and declining prices and/or increasing costs can result in reserves reported at less than the physical volumes actually thought to exist. The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are estimated by applying year-end prices of oil and gas relating to the enterprise’s proved reserves to the year-end quantities of those reserves, less estimated future expenditures (based on current costs) of developing and producing the proved reserves, and assuming continuation of existing economic conditions. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future net cash flows relating to proved oil and gas reserves.
Estimates of proved oil and gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables. Accordingly, under the allocation method used to derive the Trust’s quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and gas reserves and estimated future net revenues.
The 2004, 2003 and 2002 changes in the standardized measure of discounted future net cash flows related to future royalty income from proved reserves are as follows (in thousands):
Reserve quantities and revenues shown in the tables above for the Royalty were estimated from projections of reserves and revenues attributable to the combined BROG and Trust interests. Reserve quantities attributable to the Royalty were derived from estimates by allocating to the Royalty a portion of the total net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalty are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalty. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur. The future net cash flows were determined without regard to future federal income tax credits available to production from coal seam wells.
December average prices of $6.33 per Mcf of conventional gas, $4.82 per Mcf of coal seam gas and $38.79 per Bbl of oil were used at December 31, 2004, in determining future net revenue. The upward revision in reserve quantities for 2004 as compared to 2003 is due in part to higher oil and gas prices in December 2004 as compared to December 2003.
December average prices of $4.47 per Mcf of conventional gas, $3.31 per Mcf of coal seam gas and $28.12 per Bbl of oil were used at December 31, 2003, in determining future net revenue. The upward revision in reserve quantities for 2003 as compared to 2002 is due in part to higher oil and gas prices in December 2003 as compared to December 2002.
December average prices of $3.75 per Mcf of conventional gas, $2.80 per Mcf of coal seam gas and $24.88 per Bbl of oil were used at December 31, 2002, in determining future net revenue.
The following presents estimated future net revenues and present value of estimated future net revenues attributable to the Royalty for each of the years ended December 31, 2004, 2003 and 2002 (in thousands, except amounts per Unit):
Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the above estimates. Moreover, the present values shown above should not be considered the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would require the analysis of additional parameters.
Regulation
Many aspects of the production, pricing and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry.
Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that BROG can produce and to limit the number of wells or the locations at which BROG can drill.
Federal Natural Gas Regulation
The transportation and sale for resale of natural gas in interstate commerce, historically, have been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission (“FERC”) and its predecessor. In the past, the federal government has regulated the prices at which gas could be sold. Congress removed all non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future.
Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and FERC from 1985 to the present that affect the economics of natural gas production, transportation and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry.
Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued over the last decade by FERC and Congress will continue.
Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines.
Section 29 Tax Credit
Sales of production from coal seam wells drilled prior to January 1, 1993, including those in which the Trust holds an interest, qualified for federal income tax credits through 2002, but not thereafter. Although 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, 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.
Passive Loss Rules
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.
Other Regulation
The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, environmental protection, occupational safety, resource conservation and equal employment opportunity.
Item 3.
Item 3.
Legal Proceedings
As discussed herein under Part II, Item 9A (Controls and Procedures), due to the pass-through nature of the Trust, BROG provides much of the information disclosed in this Form 10-K and the other periodic reports filed by the Trust with the SEC. 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 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 4.
Item 4.
Submission of Matters to a Vote of Security Holders
No matters were submitted to a vote of Unit Holders, through the solicitation of proxies or otherwise, during the fourth quarter ended December 31, 2004.
PART II
Item 5.
Item 5.
Market For Registrant’s Units, Related Unit Holder Matters and Issuer Purchases of Units
The information under “Units of Beneficial Interest” at page 1 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2004, is herein incorporated by reference. The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.
Item 6.
Item 6.
Selected Financial Data
Item 7.
Item 7.
Trustee’s Discussion and Analysis of Financial Condition and Results of Operation
The “Description of the Properties” and “Trustee’s Discussion and Analysis” at pages 4 through 10 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2004, are herein incorporated by reference.
Item 7A.
Item 7A.
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 8.
Item 8.
Financial Statements and Supplementary Data
The Financial Statements of the Trust and the notes thereto at page 12 et seq., of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2004, are herein incorporated by reference.
Item 9.
Item 9.
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
Within the two most recent fiscal years, there have been no changes in and disagreements with the Trust’s independent accountants.
Item 9A.
Item 9A.
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 SEC’s rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by BROG to the Trustee and its employees who participate in the preparation of the Trust’s periodic reports 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-K and the other periodic reports filed by the Trust with the SEC.
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 the litigation described in Note 5 to the Financial Statements, 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-K and the other periodic reports provided by the Trust to the SEC.
The Trustee has evaluated the Trust’s disclosure controls and procedures as of December 31, 2004, 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 December 31, 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. 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.
Trustee’s Report on Internal Control Over Financial Reporting
TexasBank, in its capacity as trustee (the “Trustee”) of San Juan Basin Royalty Trust (the “Trust”) is responsible for establishing and maintaining adequate internal control over financial reporting. The Trust’s internal control over financial reporting is a process designed under the supervision of the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Trust’s financial statements for external purposes in accordance with a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
As of December 31, 2004, the Trustee assessed the effectiveness of the Trust’s internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control - Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, the Trustee determined that the Trust maintained effective internal control over financial reporting as of December 31, 2004, based on those criteria.
Weaver and Tidwell, L.L.P., the independent registered public accounting firm that audited the financial statements of the Trust included in this Annual Report on Form 10-K, has issued an attestation report on the Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2004. The report, which expresses unqualified opinions on the Trustee’s assessment and on the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2004, is included in this Item under the heading “Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting”.
Report of Independent Registered Public
Accounting Firm on Internal Control Over Financial Reporting
We have audited the assessment of TexasBank (the “Trustee”), included in the accompanying Trustee’s Report on Internal Control Over Financial Reporting, that San Juan Basin Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the “COSO criteria”). The Trustee is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on the Trustee’s assessment and an opinion on the effectiveness of the Trust’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating
the Trustee’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A trust’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the trust’s modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles. A trust’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the trust; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with its modified cash basis of accounting, and that receipts and expenditures of the trust are being made only in accordance with authorizations of the trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the trust’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Trustee’s assessment that the Trust maintained effective internal control over financial reporting as of December 31, 2004, is fairly stated, in all material respects, based on the COSO criteria. Also, in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on the COSO criteria.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the statements of assets, liabilities and trust corpus as of December 31, 2004 and 2003 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2004 of the Trust and our report dated March 15, 2005 expressed an unqualified opinion thereon.
/s/ Weaver and Tidwell, L.L.P.
Weaver and Tidwell, L.L.P.
Fort Worth, Texas
March 15, 2005
Item 9B.
Item 9B.
Other Information
All information required to be disclosed by the Trust in a Current Report on Form 8-K during the fourth quarter of the year ended December 31, 2004, has previously been reported on a Form 8-K.
PART III
Item 10.
Item 10.
Directors and Executive Officers of the Registrant
The Trust has no directors, executive officers or employees; the Trust is managed by a corporate trustee. Accordingly, the Trust does not have an audit committee, audit committee financial expert or a code of ethics applicable to executive officers. The Trustee, however, has adopted a policy regarding standards of conduct and conflicts of interest applicable to all directors, officers and employees of the Trustee. The Trustee is a corporate trustee which may be removed, with or without cause, at a meeting of the Unit Holders, by the affirmative vote of the holders of a majority of all the Units then outstanding.
Section 16(a) Beneficial Ownership Reporting Compliance
The Trust has no directors or officers. Accordingly, only holders of more than 10% of the Trust’s Units are required to file with the SEC initial reports of ownership of Units and reports of changes in such ownership. Based solely on a review of these reports, the Trust believes that the applicable reporting requirements of Section 16(a) of the Securities Exchange Act of 1934 were complied with for all transactions which occurred in 2004.
Item 11.
Item 11.
Executive Compensation
The Trust has no directors, executive officers or employees. Accordingly, the Trust does not have a compensation committee or maintain any equity compensation plans, and there are no Units reserved for issuance under any such plans.
During the past three years the Trustee received total remuneration as follows:
(1)
Under the Indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates for time in excess of 300 hours annually. 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).
(2)
During 2002, TexasBank served as Trustee for the period September 30, 2002 through December 31, 2002.
(3)
During 2002, Bank One, N.A. served as Trustee for the period January 1, 2002 through September 30, 2002.
Item 12.
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Security Holder Matters
The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans.
(a) Security Ownership of Certain Beneficial Owners. The following table sets forth, as of March 11, 2005, information with respect to each person known to own beneficially more than 5% of the outstanding Units of the Trust:
(1)
This information was provided to the Trust in a Form 13F-HR for the quarter ended December 31, 2004, as filed with the SEC on January 6, 2005. Francis M. Reps, Investment Advisor has sole voting power over the Units it beneficially owns.
(b) Security Ownership of Trustee. As of March 4, 2005, TexasBank beneficially owned 3,800 Units, or less than one percent of the Units. TexasBank has sole voting and dispository power over all of these Units.
Item 13.
Item 13.
Certain Relationships and Related Transactions
The Trust has no directors or executive officers and is not empowered to carry on any business activity. Accordingly, there are no relationships or related transactions to which the Trust was a party that are required to be disclosed. See Item 11 for the remuneration received by the Trustee during the year ended December 31, 2004 and Item 12 for information concerning Units owned by the Trustee.
Item 14.
Item 14.
Principal Accountant Fees and Services
The following table presents fees for professional audit services rendered by Weaver and Tidwell, L.L.P., the Trust’s principal accountants, for the audit of the Trust’s annual financial statements for the fiscal years ended December 31, 2004 and 2003 and fees billed for other services rendered to the Trust by Weaver and Tidwell, L.L.P. during those periods.
Audit Fees consist of fees billed for professional services rendered for the audit of the Trust’s annual financial statements and internal control over financial reporting, review of the interim financial statements included in the Trust’s quarterly reports and services that are normally provided by Weaver and Tidwell, L.L.P. in connection with statutory and regulatory filings or engagements.
Audit-Related Fees consist of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of the Trust’s financial statements. This category includes fees related to audit and attest services not required by statute or regulations and consultations concerning financial accounting and reporting standards.
Tax Fees consist of fees for professional services billed for tax compliance, tax advice and tax planning. These services include assistance regarding federal and state tax compliance, return preparation, preparation of the B-schedules and tax booklet.
All Other Fees consist of fees billed for products and services other than the services reported above.
The Trust has no directors or executive officers. Accordingly, the Trust does not have an audit committee and there are no audit committee pre-approval policies or procedures relating to services provided by the Trust’s independent accountants. Pursuant to the terms of the Indenture, the Trustee engages and approves all services rendered by the Trust’s independent accountants.
PART IV
Item 15.
Item 15.
Exhibits, Financial Statement Schedules
The following documents are filed as a part of this Annual Report on Form 10-K:
Financial Statements
Included in Part II of this Annual Report on Form 10-K by reference to the Trust’s Annual Report to Unit Holders for the year ended December 31, 2004:
Financial Statement Schedules
Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto.
Exhibits
*
A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
**
Filed herewith.
***
Furnished herewith.
SIGNATURE
Pursuant to the requirements of Section 13 or 15(d) 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.
SAN JUAN BASIN ROYALTY TRUST
By: TEXASBANK, AS TRUSTEE OF THE
SAN JUAN BASIN ROYALTY TRUST
/s/ Lee Ann Anderson
By:
Lee Ann Anderson
Vice President and Trust Officer
Date: March 16, 2005
(The Trust has no directors or executive officers)
EXHIBIT INDEX
*
A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
**
Filed herewith.
***
Furnished herewith.