SAN JUAN BASIN ROYALTY TRUST - Annual Report: 2006 (Form 10-K)

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

Form 10-K

 

 

Commission file number 1-8032

San Juan Basin Royalty Trust

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

 

(866) 809-4553

 

(Registrant’s telephone number, including area code)

 

Securities registered pursuant to Section 12(b) of the Act:

 

Securities registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o      No þ

 

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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Act:

Large Accelerated filer  þ     Accelerated filer  o     Non-accelerated filer  o

 

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

 

State the aggregate market value of the Units of Beneficial Interest held by non-affiliates of the registrant as of June 30, 2006: $1,814,849,777.

 

At February 26, 2007, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE

 

“Units of Beneficial Interest” at page 2; “Description of the Properties” at page 5; “Trustee’s Discussion and Analysis” at pages 5 through 11; and “Statements of Assets, Liabilities and Trust Corpus,” “Statements of Distributable Income,” “Statements of Changes in Trust Corpus,” “Notes to Financial Statements,” and “Report of Independent Registered Public Accounting Firm” at page 13 et seq., in registrant’s Annual Report to Unit Holders for the year ended December 31, 2006, are incorporated herein by reference for Item 5 (Market for Registrant’s Units, Related Security Holder Matters and Issuer Purchases of Units), Item 7 (Trustee’s Discussion and Analysis of Financial Condition and Results of Operation) and Item 8 (Financial Statements and Supplementary Data) of Part II of this Report.

 

 

PART I

 

Certain information included in this Annual Report on Form 10-K contains, and other materials filed or to be filed by the San Juan Basin Royalty Trust (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 Burlington Resources Oil & Gas Company LP’s (“BROG”), the working interest owner’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 Compass Bank, 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.

 

 

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 Compass Bank (as a result of the merger discussed below). 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.

 

On March 24, 2006 Compass Bancshares Inc., the parent company of Compass Bank, completed its acquisition of TexasBanc Holding Co., the parent company of TexasBank, the prior trustee of the Trust. On that same date, TexasBank merged with Compass Bank, and as a result, Compass Bank succeeded TexasBank as Trustee under the terms of the Indenture.

 

On February 16, 2007, Compass Bancshares, Inc. announced the signing of a definitive agreement to be acquired by Banco Bilbao Vizcaya Argentaria, S.A (“BBVA”). Under the terms of that agreement, Compass Bancshares, Inc. would become a wholly-owned subsidiary of BBVA. The transaction is expected to close in the second half of 2007 and is subject to the approval of shareholders of BBVA and Compass Bancshares, Inc. as well as to regulatory approval and customary closing conditions.

 

The Royalty was carved out of and now burdens the Underlying Properties as more particularly described under “Item 2. Properties” herein.

 

The Royalty constitutes the principal asset of the Trust. 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. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980 received one freely tradeable Unit for each share of the common stock of Southland Royalty then held. 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. On March 31, 2006, a subsidiary of ConocoPhillips completed its acquisition of Burlington Resources, Inc., BROG’s parent. As a result, ConocoPhillips became the parent of Burlington Resources, Inc., which in turn, is the parent of BROG.

 

The function of the Trustee is to collect the net proceeds attributable to the Royalty (“Royalty Income”), 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 are performed by the Trustee.

 

The Trust received approximately $136.3 million, $153.9 million and $111.0 million in Royalty Income from BROG in each of the fiscal years ended December 31, 2006, 2005 and 2004, respectively. After deducting administrative expenses and accounting for interest income and any change in cash reserves, the Trust distributed approximately $135.9 million, $151.6 million and $109.4 million to Unit Holders in each of the fiscal years ended December 31, 2006, 2005 and 2004, respectively. The Trust’s corpus was approximately $21.8 million, $23.9 million and $26.7 million as of December 31, 2006, 2005 and 2004, respectively.

 

The term “net proceeds,” as used in the Conveyance, means the excess of “gross proceeds” received by BROG during a particular period over “production costs” for such period. “Gross proceeds” means the amount received by BROG (or any subsequent owner of the Underlying Properties) from the sale of the production attributable to the Underlying Properties subject to certain adjustments. “Production costs” generally means costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes and operating charges. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to the Underlying Properties or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such amount, plus interest, at a rate specified in the Conveyance.

 

Compliance with state and federal environmental protection laws could reduce the Royalty Income received by the Trust. Costs of complying with such laws and regulations affect the production costs incurred by BROG in operating the Underlying Properties and may also affect capital expenditures by BROG. The Trust has no information regarding any estimated capital expenditures by BROG specifically allocable to environmental control facilities in the current or succeeding fiscal years.

 

Certain of the Underlying Properties are operated by BROG with the obligation to conduct its operations in accordance with reasonable and prudent business judgment and good oil and gas field practices. As operator, BROG has the right to abandon any well when, in its opinion, such well ceases to produce or is not capable of producing oil and gas in paying quantities. BROG also is responsible, subject to the terms of an agreement with the Trust, for marketing the production from such properties, either under existing sales contracts or under future arrangements at the best prices and on the best terms it shall deem reasonably obtainable in the circumstances. BROG also has the obligation to maintain books and records sufficient to determine the amounts payable to the Trustee.

 

Proceeds from production in the first month are generally received by BROG in the second month, the net proceeds attributable to the Royalty are paid by BROG to the Trustee in the third month, and distribution by the Trustee to the Unit Holders is made in the fourth month. Unit Holders of record as of the last business day of each month (the “monthly record date”) will be entitled to receive the calculated monthly distribution amount for such month on or before ten business days after the monthly record date. The amount of each monthly distribution will generally be determined and announced ten days before the monthly record date. The aggregate monthly distribution amount is the excess of (i) the net proceeds attributable to the Royalty paid to the Trustee, plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the

Trust, over (ii) the expenses and payments of liabilities of the Trust, plus any net increase in cash reserves for contingent liabilities.

 

Cash being held by the Trustee as a reserve for liabilities or contingencies (which reserves may be established by the Trustee in its discretion) or pending distribution is placed, in the Trustee’s discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any agency thereof, repurchase agreements secured by obligations issued by the United States or any agency thereof, certificates of deposit of banks having capital, surplus and undivided profits in excess of $50,000,000, or money market funds that have been rated AAAmg or AAAm by Standard & Poor’s and AA by Moody’s, subject, in each case, to certain other qualifying conditions.

 

The Underlying Properties are primarily gas producing properties. Normally there is a greater demand for gas in the winter months than during the rest of the year. Otherwise, the Royalty Income is not subject to seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities.

 

The exploration for and the production of gas and oil is a speculative business. The Trust has no means of ensuring continued income from the Royalty at the present level or otherwise. In addition, fluctuations in prices and supplies of gas and oil and the effect these fluctuations might have on royalty income to the Trust and on reserves net to the Trust cannot be accurately projected. The Trustee has no information with which to make any projections beyond information on economic conditions that is generally available to the public and thus is unwilling to make any such projections.

 

BROG has the right to sell its interest in the Underlying Properties and has recommended to the Trust that certain Underlying Properties BROG believes are marginal be sold to third parties. BROG has asked the Trust to join in the proposed sale by conveying the Royalty burdening those properties. The properties BROG proposed to sell constitute less than 2% of the value of the Royalty. The Trustee is currently evaluating whether its joinder in such a sale would be in the best interest of the Unit Holders. Any such sale would require Unit Holder approval of an amendment to the Indenture that would allow the Trustee to sell up to a specified percentage of the value of the Royalty each year without obtaining the consent of Unit Holders.

 

 

Although risk factors are described elsewhere in this Annual Report on Form 10-K, the following is a summary of the principal risks associated with an investment in Units of 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:

 

 

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 net profits 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:

 

 

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 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 assets may deplete faster than expected.

 

The Royalty Income payable to the Trust is derived from the sale of 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.

 

 

The Trust has not received any written comments from the SEC staff regarding its periodic or current reports under the Securities Exchange Act of 1934 that remain unresolved.

 

 

The Royalty conveyed to the Trust was carved out of Southland Royalty’s (now BROG’s) working interests and royalty interests 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 4,616 gross (1,286 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.

 

During 2006, in calculating Royalty Income, BROG deducted $39.2 million of capital expenditures for projects, including drilling and completion of 115 gross (24.14 net) conventional wells, two gross (0.003 net) payadds, two gross (1.74 net) recompletions, three gross (2.50 net) restimulations, 44 gross (14.63 net) coal seam wells, seven gross (0.28 net) coal seam payadds, two gross (0.048 net) coal seam recompletions, and two gross (0.08 net) coal seam miscellaneous capital projects. A payadd is the completion of an additional productive interval in an existing completed zone in a well.

 

The aggregate capital expenditures deducted by BROG in calculating Royalty Income for 2006 include approximately $12.2 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 $24.8 million for 2006 budgeted projects were deducted in calculating net proceeds payable to the Trust in calendar year 2006, and approximately $7.1 million in capital expenditures from the 2006 budget were deducted in calculating net proceeds payable to the Trust for January and February 2007. Therefore, an additional approximately $5.7 million in capital expenditures for budgeted 2006 projects remains to be spent.

 

During 2005, in calculating Royalty Income, BROG deducted approximately $19.1 million of capital expenditures for projects, including drilling and completion of 38 gross (2.72 net) conventional wells, five gross (0.011 net) payadds, one gross (0.57 net) conventional restimulation, 25 gross (2.89 net) coal seam wells, one gross (0.99 net) coal seam recavitation, two gross (0.61 net) coal seam recompletions, and five gross (0.20 net) miscellaneous coal seam capital projects. There were 110 gross (19.08 net) conventional wells, eight gross (1.73 net) payadds, six gross (3.30 net) conventional recompletions, seven gross (5.04 net) conventional restimulations, 59 gross (10.06 net) coal seam wells, five gross (2.32 net) coal seam recompletions, and one gross (0.04 net) miscellaneous coal seam capital project in progress as of December 31, 2005.

 

BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2007 is estimated at $28.0 million. Approximately $24.0 million of that budget is allocable to 112 new wells, including 33 wells scheduled to be dually completed in the Mesaverde and Dakota formations and ten wells scheduled to be dually completed in the Fruitland Coal and Pictured Cliffs formations. BROG indicates that a total of 34 of the new wells, at an aggregate cost of approximately $11.4 million, are projected to be drilled to formations producing coal seam gas. BROG reports that based on its actual capital requirements, the pace of regulatory approvals, and the mix of projects and swings in the price of natural gas, the actual capital expenditures for 2007 could range from $20.0 million to $50.0 million. BROG anticipates 416 projects, including the drilling of 67 new wells to be operated by BROG and 45 wells to be operated by third parties. Of the new BROG operated wells, 48 are projected to be conventional wells completed or dually completed to the Pictured Cliffs, Mesaverde, and/or Dakota formations, seven are scheduled to be dually completed to both conventional and coal seam formations, and the remaining 12 are projected to be completed in the Fruitland Coal formation. A total of 30 of the wells operated by third parties are projected to be conventional wells, and the remaining 15 are to be coal seam wells, with five of the 15 projected coal seam wells to be dually completed in the Fruitland Coal and Pictured Cliffs formations. The budget for 2007 reflects the continuation of a shift toward increased development of conventional gas and a reduction 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 (the “OCD”) had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. In July 2003, the OCD

approved 160-acre density in the Fruitland Coal formation. Eighty-acre density has been permitted in the Mesaverde formation since 1997.

 

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. Royalty Income for a calendar year is based on the actual gas and oil production during the period beginning with November of the preceding calendar year through October of the current calendar year. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2006, 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 40,900,570 Mcf during 2006.

 

On September 4, 1996, the Trustee announced a settlement of litigation filed by the Trustee against BROG (the “1996 Settlement”). In the 1996 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.

 

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 (“PNM”), 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. (“ChevronTexaco”), and Coral Energy Resources, L.P. (“Coral”), 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, BROG and

PNM entered into a letter agreement dated January 31, 2005, pursuant to which the parties waived 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. Neither BROG nor any of ChevronTexaco, Coral nor PNM gave notice to terminate the three contracts described above for the sale of all volumes of gas produced from the Underlying Properties and, accordingly, the terms of those contracts have been extended through March 31, 2008.

 

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 Annual Report on 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 Annual Report on 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, 2004, 2005 and 2006, were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 2003, to December 31, 2006, (in thousands):

 

 

Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2006, 2005 and 2004 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 2006, 2005 and 2004 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 $7.09 per Mcf of conventional gas, $5.48 per Mcf of coal seam gas and $58.65 per Bbl of oil were used at December 31, 2006, in determining future net revenue. The downward revision in reserve quantities for 2006 is due primarily to lower gas prices in December 2006 as compared to December 2005.

 

December average prices of $9.04 per Mcf of conventional gas, $7.05 per Mcf of coal seam gas and $54.17 per Bbl of oil were used at December 31, 2005, in determining future net revenue. The upward revision in reserve quantities for 2005 as compared to 2004 is due in part to higher oil and gas prices in December 2005 as compared to December 2004.

 

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 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, 2006, 2005 and 2004 (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 45 Tax Credit

 

Sales of gas production from certain coal seam wells drilled prior to January 1, 1993, qualified for federal income tax credits under Section 29 (now Section 45K) of the Internal Revenue Code of 1986, as amended (the “Code”), through 2002 but not thereafter. Accordingly, under present law, the Trust’s production and sale of gas from coal seam wells does not qualify for tax credit under Section 45K of the Code (the “Section 45K Tax Credit”). Congress has at various times since 2002 considered energy legislation, including provisions to reinstate the Section 45K Tax 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. For example, on August 8, 2005, new energy tax legislation was

enacted which, among other things, modified the Section 45K Tax Credit in several respects, but did not extend the credit for production from coal seam wells. No prediction can be made as to what future tax legislation affecting Section 45K of the Code may be proposed or enacted or, if enacted, its impact, if any, on the Trust and the Unit Holders.

 

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.

 

 

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 Annual Report on 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.

 

On November 11, 2005, an Arbitration Award was issued in favor of the Trust in the aggregate amount of $7,683,699 in arbitration styled San Juan Basin Royalty Trust vs. Burlington Resources Oil & Gas Company LP.  The purpose of the arbitration was to resolve certain joint interest audit issues as between the parties to the arbitration. On November 21, 2005, BROG filed its Original Petition to Vacate or to Modify or Correct Arbitration Award in the case styled Burlington Resources Oil & Gas Company LP vs. San Juan Basin Royalty Trust, No. 2005-74370, in the District Court of Harris County, Texas, 281^st Judicial District. In this litigation, BROG alleged that the award in favor of the Trust should be vacated or modified because one of the issues decided was beyond the scope of the matters agreed to be arbitrated, the award was issued in manifest disregard of applicable law, and a portion of the award is barred by limitations. BROG also sought to recover its attorneys’ fees. The Trust filed an answer and counterclaim in the litigation filed by BROG denying those allegations and asking that the arbitrator’s award be confirmed. On April 20, 2006, the Court entered an Order denying BROG’s motion to vacate and granting the Trust’s application to confirm the Arbitration Award and on June 6, 2006, rendered a final judgment in favor of the Trust. However, on May 22, 2006, BROG filed a Notice of Appeal indicating its desire to appeal the Order and any final judgment confirming the Arbitration Award and on July 5, 2006, filed a Motion for New Trial in the District Court of Harris County, Texas, urging substantially similar arguments made at the hearing. The Trust responded to the Motion for New Trial and served BROG with post-judgment discovery requests. BROG’s Motion for New Trial was overruled on August 4, 2006. BROG’s distribution to the Trust for July 2006 included $1,534,182 representing a portion of the Arbitration Award, plus accrued interest. Of this amount, $1,325,826 (the equivalent of $994,270 grossed up to account for the Trust’s 75% net overriding royalty interest) was included in calculating the net proceeds paid to the Trust, and the accrued interest thereon was $539,812. The balance of the Arbitration Award is pending BROG’s appeal, which has been assigned No. 01-06-00485-CV in the First Court of Appeals in Houston, Texas. On August 24, 2006, BROG filed its Supersedeas Bond to secure payment of the balance of the Arbitration Award, plus interest, if the appeal is dismissed or BROG does not perform the adverse judgment which becomes final on appeal. BROG filed its Brief of Appellant in the First Court of Appeals on November 29, 2006. The Trust filed its Brief of Appellee on January 29, 2007. BROG was entitled to file its reply brief on or before February 20, 2007, but on February 16, 2007, BROG filed a motion requesting an extension through March 22, 2007. Once all briefs are filed, the parties will await either a ruling on their respective requests to present oral arguments or a ruling on the merits based solely on the briefs. No reliable estimate can be given as to when the First Court of Appeals will act and it should be noted that the ruling of that Court on the merits of the appeal will itself be subject to possible discretionary review by the Texas Supreme Court.

 

In addition to the legal proceedings described above, 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.

 

 

No matters were submitted to a vote of Unit Holders, through the solicitation of proxies or otherwise, during the fourth quarter ended December 31, 2006.

 

PART II

 

 

The information under “Units of Beneficial Interest” at page 2 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2006, 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.

 

 

 

 

The “Description of the Properties” and “Trustee’s Discussion and Analysis” at pages 5 through 11 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2006, are herein incorporated by reference.

 

 

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 any business or commercial activity of any kind whatsoever, including 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.

 

 

The Financial Statements of the Trust and the notes thereto at page 13 et seq., of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2006, are herein incorporated by reference.

 

 

Within the two most recent fiscal years, there have been no changes in and disagreements with the Trust’s independent accountants.

 

 

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 (the “Exchange Act”) 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 Annual Report on 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 1996 Settlement, 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, 2006, and has concluded that such disclosure controls and procedures are effective at the “reasonable assurance” level (as such term is used in Rule 13a-15(f) of the Exchange Act) 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, 2005, there were no changes in the Trust’s internal control over financial reporting (as defined in Rule 13a-15(f) of the Exchange Act) 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

 

Compass Bank, 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, 2006, 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, 2006, 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, 2006. 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, 2006, 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 Compass Bank (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, 2006, 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, 2006, 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, 2006, 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, 2006 and 2005 and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006 of the Trust and our report dated February 28, 2007 expressed an unqualified opinion thereon.

 

Weaver and Tidwell, L.L.P.

 

Fort Worth, Texas

February 28, 2007

 

 

Not applicable.

 

 

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, 2006, has previously been reported on a Form 8-K.

 

PART III

 

 

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 2006.

 

 

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:

 

 

 

 

 

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.  As of February 26, 2007, no person was known to beneficially own more than 5% of the outstanding Units of the Trust.

 

(b) Security Ownership of Trustee.  As of February 26, 2007, Compass Bank beneficially owned 14,450 Units, or less than one percent of the Units. Compass Bank has sole voting power over all of these Units and has the sole power to dispose of 1,500 of these Units.

 

 

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, 2006 and Item 12 for information concerning Units owned by the Trustee.

 

 

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, 2006 and 2005 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

 

 

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, 2006:

 

Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus
Statements of Distributable Income
Statements of Changes in Trust Corpus
Notes to Financial Statements

 

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

 

 

 

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

 

SAN JUAN BASIN ROYALTY TRUST

 

Lee Ann Anderson

Vice President and Senior Trust Officer

 

Date: March 1, 2007

(The Trust has no directors or executive officers)

EXHIBIT INDEX