-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, IWdOMh10iPrm9XaX0kx20rIQ4mwpkYA+uY7R2rP/7NW4ayr/bQ0p4lH4q1IJMAfM 286nTjrVNCN/oujWtFswpw== 0000950134-07-004566.txt : 20070301 0000950134-07-004566.hdr.sgml : 20070301 20070301155640 ACCESSION NUMBER: 0000950134-07-004566 CONFORMED SUBMISSION TYPE: 10-K PUBLIC DOCUMENT COUNT: 16 CONFORMED PERIOD OF REPORT: 20061231 FILED AS OF DATE: 20070301 DATE AS OF CHANGE: 20070301 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SAN JUAN BASIN ROYALTY TRUST CENTRAL INDEX KEY: 0000319655 STANDARD INDUSTRIAL CLASSIFICATION: OIL ROYALTY TRADERS [6792] IRS NUMBER: 756279898 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-08032 FILM NUMBER: 07663335 BUSINESS ADDRESS: STREET 1: COMPASS BANK, TRUST DEPARTMENT STREET 2: 2525 RIDGMAR BOULEVARD SUITE 100 CITY: FORT WORTH STATE: TX ZIP: 76116 BUSINESS PHONE: 8668094553 MAIL ADDRESS: STREET 1: COMPASS BANK, TRUST DEPARTMENT STREET 2: 2525 RIDGMAR BOULEVARD SUITE 100 CITY: FORT WORTH STATE: TX ZIP: 76116 10-K 1 d44062e10vk.htm FORM 10-K e10vk
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
     
(Mark One)    
 
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2006
OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file 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)
 
     
Texas
(State or other jurisdiction of
incorporation or organization) 		  75-6279898
(I.R.S. Employer
Identification No.)
Compass Bank
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas
(Address of principal executive offices)
  76116
(Zip Code)
(866) 809-4553
 
(Registrant’s telephone number, including area code)
 
Securities registered pursuant to Section 12(b) of the Act:
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Units of Beneficial Interest   New York Stock Exchange
 
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.
 

TABLE OF CONTENTS

PART I
ITEM 1. BUSINESS
ITEM 1A. RISK FACTORS
ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 2. PROPERTIES
PART II
ITEM 5. MARKET FOR REGISTRANT’S UNITS, RELATED UNIT HOLDER MATTERS AND ISSUER PURCHASES OF UNITS
ITEM 6. SELECTED FINANCIAL DATA
ITEM 7. TRUSTEE’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A(T). CONTROLS AND PROCEDURES
ITEM 9B. OTHER INFORMATION
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
ITEM 11. EXECUTIVE COMPENSATION
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
Net Overriding Royalty Conveyance
Annual Report to Unit Holders
Consent of Cawley, Gillespie & Associates, Inc.
Certification Required by Rule 13a-14(a)
Certification Required by Rule 13a-14(b)

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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.
 
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 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


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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


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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.
 
ITEM 1A.   RISK FACTORS
 
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:
 
  •  political conditions worldwide, in particular political disruption, war or other armed conflicts in oil producing regions;
 
  •  worldwide economic conditions;
 
  •  weather conditions;
 
  •  the supply and price of foreign oil and gas;
 
  •  the level of consumer demand;
 
  •  the price and availability of alternative fuels;
 
  •  the proximity to, and capacity of, transportation facilities; and
 
  •  the effect of worldwide energy conservation measures.


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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:
 
  •  historical production from the area compared with production rates from similar producing areas;
 
  •  the assumed effect of governmental regulation; and
 
  •  assumptions about future commodity prices, production and development costs, severance and excise taxes, and capital expenditures.
 
Changes in these assumptions can materially change reserve estimates. The reserve data included herein are estimates only and are subject to many uncertainties. Actual quantities of oil and natural gas may differ considerably from the amounts set forth herein. In addition, different reserve engineers may make different estimates of reserve quantities and cash flows based upon the same available data.
 
The operators of the Underlying Properties are subject to extensive governmental regulation.
 
Oil and gas operations have been, and in the future will be, affected by federal, state and local laws and regulations and other political developments, such as price or gathering rate controls and environmental protection regulations.
 
Operating risks for BROG and other operators of the Underlying Properties can adversely affect Trust distributions.
 
Royalty Income payable to the Trust is derived from the production and sale of oil and gas, which operations are subject to risk inherent in such activities, such as blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution and other environmental risks and litigation concerning routine and extraordinary business activities and events. These risks could result in substantial losses which are deducted in calculating the net proceeds 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.


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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.
 
ITEM 1B.   UNRESOLVED STAFF COMMENTS
 
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.
 
ITEM 2.   PROPERTIES
 
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


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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


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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:
 
                                                 
    2006     2005     2004  
    Gas     Oil     Gas     Oil     Gas     Oil  
    (Mcf)     (Bbls)     (Mcf)     (Bbls)     (Mcf)     (Bbls)  
 
Production
    22,475,405       40,702       26,600,644       43,142       25,324,435       44,832  
Average Price
  $ 6.55     $ 61.30     $ 6.27     $ 49.62     $ 4.68     $ 34.81  
 
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


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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.


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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):
 
                 
    Crude
 		    Natural
 		 
    Oil     Gas  
    (Bbls)     (Mcf)  
 
Reserves as of December 31, 2003
    382       240,609  
                 
Revisions of previous estimates
    102       26,415  
Extensions, discoveries and other additions
    20       15,236  
Production
    (45 )     (25,324 )
                 
Reserves as of December 31, 2004
    459       256,936  
                 
Revisions of previous estimates
    15       14,401  
Extensions, discoveries and other additions
    23       17,023  
Production
    (43 )     (26,601 )
                 
Reserves as of December 31, 2005
    454       261,759  
                 
Revisions of previous estimates
    (33 )     (27,467 )
Extensions, discoveries and other additions
    20       8,644  
Production
    (41 )     (22,475 )
                 
Reserves as of December 31, 2006
    400       220,461  
                 
 
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):
 
                         
    2006     2005     2004  
 
Crude Oil (Bbls)
    357       395       419  
Natural Gas (Mcf)
    197,466       231,235       235,272  
 
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.


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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):
 
                         
    2006     2005     2004  
 
Balance, January 1
  $ 1,090,324     $ 756,017     $ 497,701  
Revisions of prior-year estimates, change in prices and other
    (345,237 )     339,865       272,251  
Extensions, discoveries and other additions
    28,520       72,698       47,338  
Accretion of discount
    109,032       75,602       49,770  
Royalty Income
    (136,312 )     (153,858 )     (111,043 )
                         
Balance, December 31
  $ 746,327     $ 1,090,324     $ 756,017  
                         
 
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):
 
                                                 
    2006     2005     2004  
    Estimated
 		    Present
 		    Estimated
 		    Present
 		    Estimated
 		    Present
 		 
    Future
 		    Value
 		    Future
 		    Value
 		    Future
 		    Value
 		 
    Net
 		    at
 		    Net
 		    at
 		    Net
 		    at
 		 
    Revenue     10%     Revenue     10%     Revenue     10%  
 
Total Proved
  $ 1,337,575     $ 746,327     $ 2,018,722     $ 1,090,324     $ 1,382,108     $ 756,017  
Proved Developed
  $ 1,198,784     $ 677,276     $ 1,785,597     $ 965,615     $ 1,264,556     $ 696,430  
Total Proved Per Unit
  $ 28.70     $ 16.01     $ 43.31     $ 23.39     $ 29.65     $ 16.22  
 
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.


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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


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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.
 
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 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, 281st 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.


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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.
 
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, 2006.
 
PART II
 
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 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.
 
ITEM 6.   SELECTED FINANCIAL DATA
 
                                         
    2006     2005     2004     2003     2002  
 
Royalty Income
  $ 136,311,892     $ 153,858,264     $ 111,042,767     $ 91,997,262     $ 38,053,281  
Distributable income
    135,867,325       151,560,081       109,390,735       90,357,837       36,417,967  
Distributable income per Unit
    2.915055       3.251747       2.346998       1.938644       0.781354  
Distributions per Unit
    2.915055       3.251747       2.346998       1.938644       0.781354  
Total assets, December 31
    26,481,276       43,054,656       36,814,866       36,905,104       37,972,696  
 
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 5 through 11 of the Trust’s Annual Report to Unit Holders for the year ended December 31, 2006, are herein incorporated by reference.
 
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 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.
 
ITEM 8.   FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
 
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.


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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.   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 (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.


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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.


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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.
 
/s/  Weaver and Tidwell, L.L.P.  
Weaver and Tidwell, L.L.P.
 
Fort Worth, Texas
February 28, 2007
 
ITEM 9A(T).   CONTROLS AND PROCEDURES
 
Not applicable.
 
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, 2006, has previously been reported on a Form 8-K.
 
PART III
 
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 2006.
 
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.


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During the past three years the Trustee received total remuneration as follows:
 
                         
Name of Individual
 		        Capacities in
 		    Cash
 		 
or Entity
  Year     Which Served     Compensation(1)  
 
Compass Bank(2)
    2006       Trustee     $ 249,924  
TexasBank
    2005       Trustee     $ 310,461  
TexasBank
    2004       Trustee     $ 259,472  
 
 
(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) 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.
 
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.  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.
 
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, 2006 and Item 12 for information concerning Units owned by the Trustee.
 
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


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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.
 
                 
    2006     2005  
 
Audit Fees
  $ 71,125     $ 76,065  
Audit-Related Fees
    -0-       -0-  
Tax Fees
    5,475       8,085  
All Other Fees
    -0-       -0-  
                 
Total
  $ 76,600     $ 84,150  
                 
 
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.   EXHIBITS AND 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, 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


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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
 
         
Exhibit
 		   
Number
 
Description
 
  4(a)     Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.*
  4(b)     Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules).**
  4(c)     Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.*
  10     Indemnification Agreement, dated May 13, 2003, with effectiveness as of July 30, 2002, by and between Lee Ann Anderson and San Juan Basin Royalty Trust, heretofore filed as Exhibit 10(a) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2003, is incorporated herein by reference.
  13     Registrant’s Annual Report to Unit Holders for the fiscal year ended December 31, 2006.**
  23     Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
  31     Certification required by Rule 13a-14(a), dated March 1, 2007, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, the Trustee of the Trust.**
  32     Certification required by Rule 13a-14(b), dated March 1, 2007, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank on behalf of Compass Bank, the Trustee of the Trust.***
 
 
* A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, Compass Bank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
 
** Filed herewith.
 
*** Furnished herewith.


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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: 
COMPASS BANK, AS TRUSTEE OF THE
SAN JUAN BASIN ROYALTY TRUST
 
  By: 
/s/  Lee Ann Anderson
Lee Ann Anderson
Vice President and Senior Trust Officer
 
Date: March 1, 2007
(The Trust has no directors or executive officers)


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EXHIBIT INDEX
 
         
Exhibit
 		   
Number
 
Description
 
  4(a)     Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee), heretofore filed as Exhibit 99.2 of the Trust’s Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.*
  4(b)     Net Overriding Royalty Conveyance from Southland Royalty Company to the Fort Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules).**
  4(c)     Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank, heretofore filed as Exhibit 4(c) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.*
  10     Indemnification Agreement, dated May 13, 2003, with effectiveness as of July 30, 2002, by and between Lee Ann Anderson and San Juan Basin Royalty Trust, heretofore filed as Exhibit 10(a) to the Trust’s Quarterly Report on Form 10-Q filed with the SEC for the quarter ended March 31, 2003, is incorporated herein by reference.
  13     Registrant’s Annual Report to Unit Holders for the fiscal year ended December 31, 2006.**
  23     Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
  31     Certification required by Rule 13a-14(a), dated March 1, 2007, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, the Trustee of the Trust.**
  32     Certification required by Rule 13a-14(b), dated March 1, 2007, by Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, on behalf of Compass Bank, the Trustee of the Trust.***
 
 
* A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, Compass Bank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116.
 
** Filed herewith.
 
*** Furnished herewith.


22

EX-4.(B) 2 d44062exv4wxby.htm NET OVERRIDING ROYALTY CONVEYANCE exv4wxby
 

Exhibit 4(b)
NET OVERRIDING ROYALTY CONVEYANCE
(San Juan Basin Royalty Trust)
                 
THE STATE OF NEW MEXICO
     §          
 
     §     KNOW ALL MEN BY THESE PRESENTS:
COUNTIES OF SAN JUAN,
     §          
RIO ARRIBA AND SANDOVAL
     §          
     THAT, SOUTHLAND ROYALTY COMPANY, a Delaware corporation (“Assignor”), for and in consideration of the sum of Ten Dollars ($10.00) and other good and valuable consideration to it paid by The Fort Worth National Bank, a bank organized under the laws of the United States, acting not in its individual corporate capacity but solely as trustee under that certain San Juan Basin Royalty Trust Indenture dated as of November 1, 1980 (“Assignee”), the receipt and sufficiency of which are hereby acknowledged, has bargained, sold, granted, conveyed, transferred, assigned, set over and delivered, and by these presents does hereby bargain, sell, grant, convey, transfer, assign, set over and deliver unto Assignee a net overriding royalty interest (“the Royalty Interest”) in and to the Minerals in and under, and if, as and when produced, saved and sold from, the Subject Lands during the term of the Subject Interests equal to Seventy-Five percent (75%) of the Net Proceeds attributable to the Subject Interests, as each of the above capitalized words are defined in Article I and all as more fully provided herein.
     TO HAVE AND TO HOLD the Royalty Interest, together with all and singular the rights and appurtenances thereto in anywise belonging, unto Assignee, its successors and assigns, subject, however, to the terms and provisions of this Conveyance; and Assignor does by these presents bind and obligate itself, its successors and assigns, to WARRANT and FOREVER defend all and singular the Royalty Interest unto the said Assignee, its successors and assigns, against every person whomsoever lawfully claiming or to claim the same or any part thereof by, through or under Assignor, but not otherwise.
ARTICLE I
DEFINITIONS
     As herein used the following words, terms or phrases have the following meanings:
     SECTION 1.01. “Affiliate” means, as to the party specified, any Person controlling, controlled by or under common control with such party, with the concept of control in such context meaning the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of another, whether through the ownership of voting securities, by contract or otherwise.
     SECTION 1.02. “Assignor” means the Assignor named herein while it owns all or any part of or interest in the Subject Interests and any other Person or Persons who acquire all or any part of or interest in the Subject Interests.

 

 

     SECTION 1.03. “Assignee” means the Assignee named herein while it owns all or any part of or interest in the Royalty Interest and any other Person or Persons who acquire legal title to all or any part of or interest in the Royalty Interest.
     SECTION 1.04. “Conveyance” means this Net Overriding Royalty Conveyance.
     SECTION 1.05. “Effective Date” means 7:00 o’clock A.M., local time in effect at the location of each Subject Interest, on November 1, 1980.
     SECTION 1.06. “Excess Production Costs” at any point in time means an amount equal to the excess of Production Costs over Gross Proceeds for the period ending with such point and beginning with the end of the most recent month in which there were Net Proceeds.
     SECTION 1.07. “Gross Proceeds” means the amounts received from and after the Effective Date by Assignor from the Sale of Subject Minerals sold after the Effective Date, in the aggregate, subject to the following:
          (a) There shall be excluded from Gross Proceeds all general property (ad valorem), production, severance, sales, gathering and windfall profits taxes and other taxes (whether state, federal or otherwise) assessed or levied on or in connection with the Subject Interests, the Royalty Interest or the production therefrom, or against Assignor as owner of the Subject Interests or Assignee as owner of the Royalty Interest, and which taxes are deducted or excluded from proceeds of Sale received by Assignor.
          (b) There shall be excluded any amount for Subject Minerals attributable to nonconsent operations conducted with respect to the Subject Interests (or any portion thereof) as to which Assignor shall be a nonconsenting party and which is dedicated to the recoupment or reimbursement of costs and expenses of the consenting party or parties by the terms of the relevant operating agreement, unit agreement, contract for development or other instrument providing for such nonconsent operations, provided Assignor’s election not to participate in such operations is made in conformity with the provisions of Section 6.01 of this Conveyance.
          (c) There shall be excluded any amount which Assignor shall receive as any of the following: consideration for transfer or sale of any of the Subject Interests (subject to the Royalty Interest) or equipment or other personal property or fixtures on the Subject Lands; delay rental; shut-in gas well royalty or payment; minimum royalty (to the extent not attributable to actual production of the Subject Minerals); payments for gas not taken, when such payments are made (but to the extent such payments are allocated to gas taken in the future such payments shall be included without interest in Gross Proceeds when such gas is taken); damages arising from any cause other than drainage or reservoir injury; rental for reservoir use; payments made to Assignor in connection with the drilling of any well on any of the Subject Lands or lands in the vicinity (such exclusion including dry and bottom hole payments, provided that if such well is drilled on the Subject Lands and Assignor incurs Production Costs in connection therewith such payments shall reduce Production Costs) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; provided

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there shall be included in Gross Proceeds advance or prepaid payments for future production received by Assignor to the extent not subject to repayment in the event of insufficient subsequent production (and to the extent so subject to repayment shall be included without interest in Gross Proceeds when the Minerals on which such payment was so advanced or prepaid are actually produced) and payments made to Assignor in connection with the deferring of drilling of any well on any of the Subject Lands (including payments from an operator in the vicinity for refraining from drilling an offset well).
          (d) There shall be excluded any amount for Subject Minerals lost in the production or marketing thereof or used by Assignor in conformity with ordinary or prudent practices for drilling, production and plant operations (including gas injection, secondary recovery, pressure maintenance, repressuring, cycling operations, plant fuel or shrinkage) conducted for the purpose of drilling for, producing or processing Subject Minerals or for operations on any unit or plant to which the Subject Interests are committed, but only so long as such Subject Minerals are so used.
          (e) Amounts received as a loan by Assignor from a purchaser of Subject Minerals, whether with or without interest, shall not be considered to be derived from the sale of Subject Minerals, provided that the related Sales Contract meets the requirements of Section 4.01 hereof.
          (f) So long as and to the extent that the same may be required by applicable laws and regulations, in the case of any Subject Interest derived under a lease from the United States of America from which the average production of oil per well per day averaged on the monthly basis is 15 barrels or less, the obligation to pay and the right of Assignee to receive the proceeds of oil produced from such lease shall be suspended until said average production of oil per well per day exceeds said minimum amount, and such suspension shall apply separately to any zone or portion of such lease segregated for computing government royalties.
          (g) If a controversy or possible controversy exists (whether by reason of any statute, order, decree, rule, regulation, contract or otherwise) between Assignor and any purchaser as to the correct sales price of any Subject Mineral or, for any other reason, as to Assignor’s right to receive or collect the proceeds of sale of any Subject Minerals, then
                    (i) amounts withheld by the purchaser or deposited by it with an escrow agent shall not be considered to be received by Assignor until actually collected by Assignor, but the amounts received by Assignor shall include any interest, penalty or other amount paid to Assignor in respect thereof;
                    (ii) amounts received by Assignor and promptly deposited by it with an escrow agent shall not be considered to have been received by Assignor, but all amounts thereafter paid to Assignor by such escrow agent shall be considered to be amounts received from the sale of Subject Minerals; and

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                    (iii) amounts received by Assignor and not deposited with an escrow agent shall be considered to be received for purposes of this Section 1.07.
          (h) Assignor shall have the right to contest the amount of the windfall profits tax alleged to be due on proceeds included in Gross Proceeds and to seek refunds thereof. In the event any amounts are required to be paid because of any deficiency in prior payment of windfall profits tax for periods after the Effective Date, the amounts so paid shall be included in Production Costs as paid.
     SECTION 1.08. “Minerals” means oil, gas and all other minerals produced in association with oil or gas, but excluding all other minerals, whether similar or dissimilar.
     SECTION 1.09. “Monthly Record Date” for each month means the close of business on the last day of such month which is not a Saturday, Sunday or other day on which national banking institutions in the City of Fort Worth, Texas, are closed as authorized or required by law, unless Assignee determines that a later date is required to comply with applicable law or the rules of an exchange pursuant to the terms of the San Juan Basin Royalty Trust Indenture referred to above.
     SECTION 1.10. “Net Proceeds” for any period means the excess of Gross Proceeds realized during such period over the sum of (a) Production Costs incurred during such period and (b) Excess Production Costs as of the end of the immediately preceding period.
     SECTION 1.11. “Non-Affiliate” means, as to the party specified, any Person who is not an Affiliate of such party.
     SECTION 1.12. “Person” means any individual, corporation, partnership, trust, estate or other entity, organization or association.
     SECTION 1.13. “Prime Interest Rate” means the interest rate per annum charged by Morgan Guaranty Bank of New York on ninety day loans to its most substantial and responsible commercial borrowers.
     SECTION 1.14. “Processing Costs” means the costs to Assignor of manufacturing, refining or processing (all herein referred to as “processing”) gas and casinghead gas included in the Subject Minerals before the Sale thereof, which costs for purposes hereof shall consist of
          (a) the sum of (i) any such processing charges paid to Non-Affiliates and (ii) the expenses (including depreciation but otherwise not including capital costs) incurred by Assignor or its Affiliate in processing such Subject Minerals plus an amount equal to a return of 15% on the depreciated book value of the fixed assets used in such processing (for which purpose of computing depreciation and the return on depreciated book value the value of fixed assets owned by Assignor will be their book value as of the date first used in processing Subject Minerals), or
          (b) if greater, the amount allowed as processing charges by any Federal or State agency having jurisdiction over the sale of such Subject Minerals.

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If Assignor or an Affiliate receives a share of the production of others or of plant products therefrom (or proceeds of sale thereof) for processing such production of others, such share shall not be included in Subject Minerals (or Gross Proceeds). If Assignor or an Affiliate does not bear any processing costs but the owners or operators of a plant receive a share of the Subject Minerals (or proceeds of sale thereof) for processing them, such share (or proceeds) shall be excluded from the Subject Minerals (and Gross Proceeds).
     SECTION 1.15. “Production Costs” means, on an accrual accounting method and accruing with respect to the following from and after the Effective Date, and whether capital or non-capital in nature,
          (a) the sum of
                    (i) all amounts borne by Assignor as any of the following: royalty; overriding royalty or other presently existing burden against production or the proceeds of sale of production attributable to the Subject Interests; delay rental; shut-in gas well royalty or payment; minimum royalty; payments to lessors or others in the area in connection with the drilling or deferring of drilling of any well on any of the Subject Lands or lands in the vicinity (including dry and bottom hole payments and payments made to others for refraining from drilling an offset well) or in connection with any adjustment of any well and leasehold equipment upon unitization of any of the Subject Interests; and rent and other consideration paid for use of or damage to the surface;
                    (ii) all general property (ad valorem), production, severance, sales, gathering and windfall profits taxes and other taxes (whether state, federal or otherwise), except income taxes, assessed or levied on or in connection with the Subject Interests, the Royalty Interest or the production therefrom or equipment on the Subject Lands, or against Assignor as owner of the Subject Interests or Assignee as owner of the Royalty Interest, and which taxes are paid by Assignor, and any income tax on the Royalty Interest paid by Assignor;
                    (iii) the aggregate costs incurred by Assignor under any joint operating agreement applicable to the Subject Interests to which Assignor and one or more Non-Affiliates are parties;
                    (iv) The aggregate costs incurred by Assignor under Schedule B attached hereto with respect to any Subject Interest not subject to a joint operating agreement between Assignor and a Non-Affiliate.
                    (v) all other costs, expenses and liabilities of investigating, exploring, prospecting, drilling and mining for, operating and producing Subject Minerals and sale and marketing thereof, including without implied limitation: costs of equipping, plugging back, reworking, completing, recompleting and plugging and abandoning of any well on the Subject Lands and of making the Subject Minerals ready or available for market; the cost of construction of gathering lines, tanks, transmission lines, meters and other production and delivery facilities and of

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transporting, compressing, dehydrating, separating, treating, storing and marketing the Subject Minerals; the cost of secondary recovery, pressure maintenance, repressuring, cycling and other operations conducted for the purpose of enhancing production; and the cost of litigation concerning title to or operation of the Subject Interests and any other acts or omissions of Assignor consistent herewith or brought by Assignor to protect the Subject Interests;
                    (vi) Processing Costs;
                    (vii) interest accrued during any month in which there were Excess Production Costs computed at the Prime Interest Rate in effect at the end of such period on the amount of Excess Production costs at the end of such period;
                    (viii) the costs of the audits furnished pursuant to Section 2.06 hereof;
                    (ix) any amounts paid by Assignor, whether as refund, interest or penalty, to a purchaser because the amount initially received by Assignor as sales price was more or allegedly more than permitted by the terms of any applicable contract, statute, regulation, order, decree or other obligation;
                    (x) any other amounts paid by Assignor with respect to the Subject Interests or operation thereof or sale of production therefrom, whether as refund, fine, interest or penalty, pursuant to litigation or settlement of threatened litigation or order of governmental agency, provided that Assignor has not breached Section 6.01 hereof; and
                    (xi) all consideration hereafter paid and costs and expenses hereafter incurred by Assignor for any renewals or extensions of leases or other rights hereafter acquired which are included in the definition herein of Subject Interests;
          (b) but excluding
                    (i) costs which would otherwise be treated as Production Costs but which shall not be so treated for purposes hereof (until the following amounts have been fully credited against such costs) equal to amounts reimbursed or credited to Assignor by insurance from damage to property, by sales of property or transfers of property off the leases included in the Subject Interests or by proceeds from unitization or other disposition of property;
                    (ii) the costs incurred in drilling a well to a lower depth than that to which the Subject Interests are by the definition below limited unless the well is ultimately completed as a producer within the depths included in the Subject Interests and is not completed as a producer below such depths and, even in such event, the cost of drilling below such depths (as allocated by Assignor) shall be excluded; and
                    (iii) any amounts which would otherwise be Production Costs but which are attributable to periods before the Effective Date.

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     SECTION 1.16. “Sale” includes exchanges and other dispositions for value.
     SECTION 1.17. “Sales Contracts” means all contracts and agreements for the offer or sale of, or commitment to offer or sell, or right of first refusal to purchase, Subject Minerals.
     SECTION 1.18. “Subject Interests” means each kind and character of right, title, claim or interest which Assignor has on the Effective Date in the oil, gas or mineral leases, mineral interests, royalty interests and overriding royalty interests and the unitization and pooling agreements and the units created thereby which are described in Schedule A, and all the right, title, claim or interest which Assignor has on the Effective Date in and to the Subject Lands, whether such right, title, claim or interest be under and by virtue of a lease, a mineral deed or reservation, a royalty deed or reservation, an overriding royalty assignment or reservation, a unitization or pooling agreement, a unitization or pooling order, an operating agreement, a division order, a transfer order or any other type of contract, conveyance or instrument or under any other type of claim or title, legal or equitable, recorded or unrecorded, even though Assignor’s interests be incorrectly or incompletely described in, or a description thereof be omitted from, Schedule A, all as the same shall be enlarged by the discharge of any payments out of production or by the removal of any charges or encumbrances to which any of the same are subject and any and all renewals and extensions of any of the same, but subject to all burdens to which Assignor’s such right, title, claim or interest is subject (while same remains so subject), limited, however, as follows: (i) limited to the depths to which the definition below of “Subject Lands” is limited, (ii) limited, as to duration, with respect to each Subject Interest which is a mineral interest subject on the Effective Date to an oil and gas lease (or oil, gas and mineral lease), whether or not owned in whole or in part by Assignor, or which is a royalty interest as to which the underlying mineral estate is subject to such a lease, to the life of that lease or any renewal or extension thereof (so that if a lease in force on the Effective Date should terminate in whole or in part for any reason and not be renewed or extended then such Subject Interest, to the extent same, or the underlying mineral estate in same, is no longer subject to such lease, shall no longer be subject to this Conveyance and the rights, titles and interests therein hereby conveyed shall revert to Assignor without necessity of written proof so evidencing) and (iii) limited, if Assignor’s interest in any Subject Interest should terminate sooner than the reversion provided in the foregoing (ii), to the period to which Assignor’s interest in such Subject Interest is limited. There shall be excluded from the term “Subject Interests” any interest hereafter acquired by Assignor in and to any of the Subject Lands, except any interest acquired pursuant to existing agreements for no new consideration and renewals or extensions of leases. For purposes of this Conveyance “renewals or extensions” of any lease shall be limited to renewals or extensions of an existing lease obtained by the present owner thereof (or such owner’s successors in interest) while such lease is in force or within six months after such lease terminates. Assignor shall be under no duty to seek renewals or extensions of any lease.
     SECTION 1.19. “Subject Lands” means the lands which are described in or which are subject to the oil, gas and mineral leases, mineral deeds, royalty deeds, assignments and other instruments described in Schedule A attached hereto from the surface of such lands to the base of the “Basin-Dakota Gas Pool” as defined in Rule 25 of Order No. R-1670-C (as amended to the date hereof) issued by the New Mexico Oil Conservation Commission, provided that if Assignor’s ownership rights in any such lands are presently limited to depths shallower than such depth the “Subject Lands” shall likewise be subject to such limitation and provided further that

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where the description in Schedule A excepts land or refers to an instrument insofar only as it covers certain land, no interest in such excepted land or in land other that to which such reference is limited shall be included in the terms “Subject Lands” or “Subject Interests”.
     SECTION 1.20. “Subject Minerals” means all Minerals in and under, and which may be produced, saved and sold from, and which shall accrue and be attributable to, the Subject Interests, including plant products attributable thereto from processing gas or casinghead gas included in the Subject Minerals before sale thereof (but not including products derived from processing oil).
ARTICLE II
RECORDS AND REPORTS
     SECTION 2.01. Books and Records. Assignor shall at all times maintain true and correct books and records sufficient to determine the amounts payable to Assignee hereunder, including, but not limited to, a Net Proceeds account to which Gross Proceeds and Production Costs are credited and charged.
     SECTION 2.02. Inspections. The books and records referred to in Section 2.01 shall be open for inspection at the office of Assignor during normal business hours.
     SECTION 2.03. Quarterly Statements. Within thirty (30) days next following the close of each calendar quarter, Assignor shall deliver to Assignee a statement showing the computation of Net Proceeds attributable to such quarter.
     SECTION 2.04. Assignee’s Exceptions to Quarterly Statements. If Assignee shall take exception to any item or items included in the quarterly statements rendered by Assignor, Assignee shall notify Assignor in writing within 180 days after the receipt of the report and annual audit furnished pursuant to Section 2.06 hereof, setting forth in such notice the specific charges complained of and to which exception is taken or the specific credits which should have been made and allowed; and, with respect to such complaints and exceptions as are justified, adjustment shall be made. If Assignee shall fail to give Assignor notice of such complaints and exceptions prior to the expiration of such 180 days period, then the statements for such calendar year as originally rendered by Assignor shall be deemed to be correct as rendered.
     SECTION 2.05. Geological Data. Upon request Assignor shall, subject to the limitations of confidentiality undertakings with co-owners or other third parties, furnish to Assignee access to all geological, well and production data which Assignor has on hand relating to operations on the Subject Interests. Assignor shall also furnish to Assignee quarterly reports showing the status of development, producing and other operations conducted by Assignor on the Subject Interests. All information furnished to Assignee pursuant to this section is confidential and for the sole benefit of Assignee and shall not be shown by Assignee to any other Person.
     SECTION 2.06. Annual Audits and Reports. Within 90 days after the end of the calendar year, Assignor shall deliver to Assignee a statement which has been audited by a

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nationally recognized firm of independent public accountants selected by Assignor, which shall show the information provided for in Section 2.03 on an annual basis.
ARTICLE III
PAYMENT
     SECTION 3.01. Payment. On or before the Monthly Record Date, Assignor shall pay to Assignee as a royalty and overriding royalty hereunder an amount equal to Seventy-Five percent (75%) of the Net Proceeds for the preceding month. On December 31, 1980, Assignor shall pay to Assignee as an advance royalty the sum of $1,000,000. Such amount shall be subtracted from the amounts otherwise payable under this Section with respect to future periods.
     SECTION 3.02. Interest on Past Due Payments. Any amount not paid by Assignor to Assignee when due shall bear, and Assignor will pay, interest at the rate of four percentage points over the Prime Interest Rate, determined at the end of each month, from such due date until such amount is paid, but not in excess of the maximum amount allowed by law.
     SECTION 3.03. Overpayment. If at any time Assignor inadvertently pays Assignee more than the amount due, Assignee shall not be obligated to return any such overpayment, but the amount or amounts otherwise payable to Assignee for any subsequent period or periods shall be reduced by such overpayment, plus an amount equal to interest computed at 120% of the weighted average Prime Interest Rate in effect during the period of such overpayment.
ARTICLE IV
MARKETING OF SUBJECT MINERALS
     SECTION 4.01. Sales Contracts. Assignor, to the extent it has the right to do so, shall market or cause to be marketed the Subject Minerals. For such purpose, sales of Subject Minerals may continue to be made pursuant to existing Sales Contracts. Assignor may amend such existing Sales Contracts and may enter into one or more Sales Contracts in the future at the best prices and on the best terms Assignor shall deem reasonably obtainable in the circumstances. Gross Proceeds of Subject Minerals subject to Sales Contracts shall be determined on the basis of amounts actually received by Assignor from sales under the Sales Contracts regardless of whether at the time of production or sale market value should be different from proceeds of sale.
     SECTION 4.02. Performance of Sales Contracts. Assignor will duly perform all obligations binding on it under all Sales Contracts in accordance with the terms thereof and will take all appropriate and reasonable measures to enforce the performance under each of the Sales Contracts of the obligations of the purchaser thereunder. All Subject Minerals sold by Assignor, whether pursuant to Sales Contracts or otherwise, shall be delivered by Assignor to the purchasers thereof, into the pipelines to which the wells producing such Subject Minerals may be connected or to such other point of purchase as is reasonably required in the marketing of such Subject Minerals.

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     SECTION 4.03. Reliance by Third Party. As to any party, the acts of Assignor shall be binding on Assignee. It shall not be necessary for Assignee to join with Assignor in any division or transfer order or any Sales Contract, and proceeds of sale of the Subject Minerals shall be paid by the purchasers thereof (or others disbursing proceeds) directly to Assignor without necessity of joinder by or consent of Assignee.
ARTICLE V
NON-LIABILITY OF ASSIGNEE
     In no event shall Assignee be liable or responsible in any way for any Production Costs or other costs or liabilities incurred by Assignor or others attributable to the Subject Interests or to the Minerals produced therefrom.
ARTICLE VI
OPERATION OF SUBJECT INTERESTS
     SECTION 6.01. Prudent Operator Standard. Assignor agrees, to the extent it has the legal right to do so under the terms of any lease, operating agreement, unit operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof), that it will conduct and carry on the maintenance and operation of the Subject Interests with reasonable and prudent business judgment and in accordance with good oil an gas field practices, and that it will drill such wells as a reasonably prudent operator would drill from time to time in order to protect them from drainage. However, nothing contained in this Section 6.01 shall be deemed to prevent or restrict Assignor from electing not to participate in any operation which is to be conducted under the terms of any operating agreement, unit operating agreement, contract for development or similar instrument affecting or pertaining to the Subject Interests (or any portion thereof) and allowing consenting parties to conduct nonconsent operations thereon, if such election is made by Assignor in good faith. Notwithstanding anything elsewhere herein to the contrary, Assignor shall never be liable to Assignee for the manner in which Assignor performs its duties hereunder as long as Assignor has acted in good faith.
     SECTION 6.02. Abandonment of Properties. Nothing herein contained shall obligate Assignor to continue to operate any well or to operate or maintain in force or attempt to maintain in force any of the Subject Interests when, in Assignor’s opinion, such well or Subject Interest ceases to produce or is not capable of producing oil or gas in paying quantities. The expiration of a Subject Interest in accordance with the terms and conditions applicable thereto shall not be considered to be a voluntary surrender or abandonment thereof.
     SECTION 6.03. Insurance. Although Assignor is permitted to carry policies of insurance covering the property upon the Subject Interests and risks incident to the operation thereof and to charge premiums therefor to the Net Proceeds account, Assignor shall not be required to carry insurance on such property or covering any of such risks unless it elects so to do. In no event shall Assignor be liable to Assignee on account of any losses sustained which are not covered by insurance.

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ARTICLE VII
UNITIZATION
     SECTION 7.01. Pooled Subject Interests. Certain of the Subject Interests may have been heretofore pooled and unitized for the production of Minerals. Such Subject Interests are and shall be subject to the terms and provisions of such pooling and unitization agreements, and the Royalty Interest in each such Subject Interest shall apply to and affect only the production from such units which accrues to such Subject Interest under and by virtue of the applicable pooling and unitization agreements.
     SECTION 7.02. Right to Pool and Process. Assignor shall have the right and power, exercisable only during the period provided in Section 7.03 hereof, (a) to pool and unitize any of the Subject Interests and to alter, change or amend or terminate any pooling or unitization agreements heretofore or hereafter entered into, as to all or any part of the land covered hereby, as to any one or more of the formations or horizons hereunder, and as to any one or more Minerals, upon such terms and provisions as Assignor shall in its sole discretion determine, and (b) to commit any of the Subject Interests (including the Royalty Interest attributable thereto) to an agreement for processing same (pursuant to which, by way of example and not by way of limitation, the plant owner or operator receives a portion of the Subject Minerals or plant products therefrom or proceeds of the sale thereof as a fee for processing). If and whenever through the exercise of such right and power, or pursuant to any law hereafter enacted or any rule, regulation or order of any governmental body or official hereafter promulgated, any of the Subject Interests are pooled or unitized in any manner, the Royalty Interest insofar as it affects such Subject Interest shall also be pooled and unitized, and in any such event such Royalty Interest in such Subject Interest shall apply to and affect only the production which accrues to such Subject Interest under and by virtue of the pooling and unitization.
     SECTION 7.03. Applicable Period. Assignor’s power and rights in Section 7.02 shall be exercisable only during the period of the life of the last survivor of the descendants of the signers of the Declaration of Independence living on the date of execution hereof, plus twenty-one (21) years after the death of such last survivor, or the term of this Conveyance, whichever period shall first expire.
ARTICLE VIII
GOVERNMENT REGULATION
     All obligations of Assignor hereunder shall be subject to all applicable provisions of the Emergency Petroleum Allocation Act of 1973, the Department of Energy Organization Act, the Natural Gas Act, the Natural Gas Policy Act of 1978 and each other statute purporting to provide regulation of the sale of Minerals or establishing maximum prices at which the same may be sold and all applicable laws, orders, rules and regulations thereunder of the Federal Energy Regulatory Commission, the Department of Energy and each other legislative or governmental body, agency, board or commission having jurisdiction. Rates permitted under the Natural Gas Act, the Natural Gas Policy Act of 1978, the Emergency Petroleum Allocation Act of 1973 and each such other statute and the rules and regulations thereunder to be paid for the Subject

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Minerals shall be controlling if lower than prices established in Sales Contracts. Assignor shall be entitled to use its reasonable discretion in making filings, for itself and on behalf of Assignee, with the Federal Energy Regulatory Commission, the Department of Energy or any other governmental body, agency, board or commission having jurisdiction, affecting the price or prices at which Subject Minerals may be sold, and with purchasers of production, operators or others with respect to the windfall profits tax.
ARTICLE IX
ASSIGNMENTS
     SECTION 9.01. Assignment by Assignor. Assignor shall have the right to assign, sell, transfer, convey, mortgage or pledge the Subject Interests, or any part thereof, subject to the Royalty Interest and the terms and provisions of this Conveyance. From and after the effective date of any such assignment, sale, transfer or conveyance by Assignor, the assignee thereunder shall succeed to all the requirements upon and responsibilities of Assignor hereunder, as to the interests so acquired by such assignee, and, from and after the said effective date, Assignor shall be relieved of such requirements and responsibilities, excepting only those accrued or due for performance prior to such effective date.
     SECTION 9.02. Partial Assignment. If Assignor assigns its interest under the Subject Interests as to some of such Subject Interests or as to some part thereof, then, effective as of the date of such assignment, in determining the Royalty Interest payable with respect to production from such assigned Subject Interests or parts thereof, the Gross Proceeds, Production Costs and Net Proceeds attributable to such assigned interests will be computed and determined by the assignee of such assigned interests in the aggregate as to the assigned interests owned by such assignee, but separate from and not aggregated with the computation and determination made by Assignor as to unassigned interests.
     SECTION 9.03. Assignment by Assignee. Assignee has the right to assign the Royalty Interest in whole or in part, but (with respect to the assignee named herein) only as authorized by the San Juan Basin Royalty Trust Indenture referred to above. However, no such assignment will affect the method of computing Net Proceeds, and if more than one Person becomes entitled to participate in the Royalty Interest, Assignor may withhold from such other Person payments to which such Person would otherwise be entitled hereunder and the furnishing of any data or information which Assignor is required by the terms hereof to furnish Assignee until Assignor is furnished a recordable instrument executed by or binding upon all Persons interested in the Royalty Interest designating one Person who is to receive such payments, data and information. In making conveyances or assignments of any of the Subject Interests (to the extent permitted hereunder), Assignee need not vest in its grantee or assignee all of the rights of Assignee hereunder with respect to the interest in the Subject Interests so conveyed or assigned.
     SECTION 9.04. Change in Ownership. No change of ownership or right to receive payment of the Royalty Interest, or of any part thereof, however accomplished, shall be binding upon Assignor until notice thereof shall have been furnished by the Person claiming the benefit thereof, and then only with respect to payments thereafter made. Notice of Sale or assignment shall consist of a certified copy of the recorded instrument accomplishing the same; notice of

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change of ownership or right to receive payment accomplished in any other manner (for example by reason of incapacity, death or dissolution) shall consist of certified copies of recorded documents and complete proceedings legally binding and conclusive of the rights of all parties. Until such notice shall have been furnished Assignor as above provided, the payment or tender of all sums payable on the Royalty Interest may be made in the manner provided herein precisely as if no such change in interest or ownership or right to receive payment had occurred. The kind of notice herein provided shall be exclusive, and no other kind, whether actual or constructive, shall be binding on Assignor.
     SECTION 9.05. Rights of Mortgagee or Trustee. If Assignee shall at any time execute a mortgage or deed of trust covering all or part of the Royalty Interest, the mortgagee(s) or trustee(s) therein named or the holder of any obligation secured thereby shall be entitled, to the extent such mortgage or deed of trust so provides, to exercise all the rights, remedies, powers and privileges conferred upon Assignee by the terms of this Conveyance and to give or withhold all consents required to be obtained hereunder by Assignee, but the provisions of this Section 9.05 shall in no way be deemed or construed to impose upon Assignor any obligation or liability undertaken by Assignee under such mortgage or deed of trust or under the obligation secured thereby.
ARTICLE X
MISCELLANEOUS
     SECTION 10.01. Proportionate Reduction. In the event of failure or deficiency in title to any of the Subject Interests, the portion of the production from such Subject Interest out of which the Royalty Interest attributable to such Subject Interest shall be payable shall be reduced in the same proportion that such Subject Interest is reduced.
     SECTION 10.02. Term. Subject to the limitations stated in Section 1.18 hereof, this Conveyance shall remain in force so long as any of the Subject Interests are in effect.
     SECTION 10.03. Further Assurances. Should any additional instruments of assignment and conveyance be required to describe more specifically any interests subject hereto, Assignor agrees to execute and deliver the same. Also, if any other or additional instruments are required in connection with the transfer of State, Federal or Indian lease interests in order to comply with applicable laws, regulations or agreements, Assignor will execute and deliver the same.
     SECTION 10.04. Notices. All notices, statements, payments and communications between the parties hereto shall be deemed to have been sufficiently given and delivered if enclosed in a post paid wrapper and deposited in the United States Mails directed, or if personally delivered, to the party to whom the same is directed or to be furnished or made at the respective addresses, as follows:

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Southland Royalty Company
1000 Fort Worth Club Tower
Fort Worth, Texas 76102
Attention: Treasurer
The Fort Worth National Bank
Post Office Box 2050
Fort Worth, Texas 76101
Attention: Trust Department
     Either party or the successors or assignees of the interest or rights or obligations of either party hereunder may change its address or designate a new or different address or addresses for the purposes hereof by a similar notice given or directed to all parties interested hereunder at the time.
     SECTION 10.05. Binding Effect. This Conveyance shall bind and inure to the benefit of the successors and assigns of Assignor and Assignee.
     SECTION 10.06. Governing Law. The validity, effect and construction of this Conveyance shall be governed by the laws of the State of New Mexico.
     SECTION 10.07. Headings. Article and Section headings used in this Conveyance are for convenience only and shall not affect the construction of this Conveyance.
     SECTION 10.08. Substitution of Warranty. This instrument is made with full substitution and subrogation of Assignee in and to all covenants of warranty by others heretofore given or made with respect to the Subject Interests or any part thereof or interest therein.
     SECTION 10.09. Counterpart Execution. This Conveyance may be executed in multiple counterparts, each of which shall be an original. Certain counterparts may have descriptions relating to different recording jurisdictions omitted from Schedule A. A counterpart with all such descriptions is being filed for record in San Juan County, New Mexico.

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     IN WITNESS WHEREOF, each of the parties hereto has caused this agreement to be executed in its name and behalf and its corporate seal to be affixed hereto and attested by its proper signatory officers thereunto duly authorized, as of November 1, 1980.
                 
ATTEST:       SOUTHLAND ROYALTY COMPANY    
 
                
  /s/ Lucy H. Lowry
 
Lucy H. Lowry, Secretary
      By   : /s/ Alton C. Goodrich
 
 Alton C. Goodrich 		   
 
          Executive Vice President    
 
                
ATTEST:       The Fort Worth National Bank
acting not in its individual capacity
but solely as the Trustee of the
San Juan Basin Royalty Trust
    
 
                
  /s/ Palmer S. Haffner, Jr.
      By:   /s/ Bruce Petty    
 
 Palmer S. Haffner, Jr.
         
 
 Bruce Petty 		   
Trust Officer
          Executive Vice President and    
 
          Trust Officer    

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THE STATE OF TEXAS                     §
COUNTY OF TARRANT                    §
     The foregoing instrument was acknowledged before me this third day of November, 1980 by ALTON C. GOODRICH, Executive Vice President of Southland Royalty Company, a corporation, on behalf of said corporation.
     GIVEN UNDER MY HAND AND SEAL OF OFFICE, this the third day of November, 1980.
             
 
        /s/ Diana Marsh
 
 Notary Public in and for Tarrant 		   
 
                          County,Texas    
My Commission Expires:
            
 
            
     December 31, 1980
 
 
            
THE STATE OF TEXAS                     §
COUNTY OF TARRANT                    §
     The foregoing instrument was acknowledged before me this third day of November, 1980 by BRUCE PETTY, Executive Vice President and Trust Officer of The Forth Worth National Bank, a banking association organized under the laws of the United States, on behalf of said corporation.
     GIVEN UNDER MY HAND AND SEAL OF OFFICE, this the third day of November, 1980.
             
 
        /s/ Diana Marsh
 
 Notary Public in and for Tarrant 		   
 
                          County, Texas    
My Commission Expires:
            
 
            
     December 31, 1980
 
 
            

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EX-13 3 d44062exv13.htm ANNUAL REPORT TO UNIT HOLDERS exv13
 

Exhibit 13
(GRAPHIC)
San Juan Basin Royalty Trust 2006 ANNUAL REPORT & and Form 10 — K &

 

 

(GRAPHIC)
No 1

 

 

The Trust
 
THE PRINCIPAL ASSET of the San Juan Basin Royalty Trust (the “Trust”) consists of a 75% net overriding royalty interest (the “Royalty”) carved out of certain oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties located in the San Juan Basin of northwestern New Mexico.
Units of Beneficial interest
The units of beneficial interest of the Trust (the “Units”) are traded on the New York Stock Exchange under the symbol “SJT.” At February 26, 2007, the closing price of a Unit was $31.98. From January 1, 2005, to December 31, 2006, the quarterly high and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows:
                         
                    DISTRIBUTIONS  
    HIGH     LOW     PAID  
 
2006
                        
 
                        
First Quarter
   $ 45.9900     $ 36.0000     $ 1.083276  
Second Quarter
     43.7500       33.0000       .599299  
Third Quarter
     41.2500       32.8200       .666989  
Fourth Quarter
     39.0000       32.6200       .565491  
 
                      
TOTAL FOR 2006
                   $ 2.915055  
 
                      
 
                        
2005
                        
First Quarter
   $ 37.4000     $ 27.7000     $ .831092  
Second Quarter
     44.2000       34.1000       .740612  
Third Quarter
     51.4300       39.0000       .692829  
Fourth Quarter
     49.2500       38.3000       .987214  
 
                      
TOTAL FOR 2005
                   $ 3.251747  
 
                      
At February 16, 2007, there were 46,608,796 Units outstanding held by 1,709 Unit holders of record. The following table presents information relating to the distribution of record ownership of Units:
                 
    NUMBER OF    
type of unit holders   UNIT HOLDERS   UNITS HELD
 
Individuals, Joint Holders and Minors
     1,504       1,888,965  
Fiduciaries
     162       495,464  
Government Bodies
     1       30  
Clubs, Associations or Societies
     7       13,120  
Depositary (for all beneficial holders)
     1       43,864,558  
Corporations
     34       346,659  
 
                
TOTAL
     1,709       46,608,796  
 
                
No 2

 

 

To Unit Holders
(GRAPHICS)WE ARE PLEASED TO PRESENT THE 2006 ANNUAL REPORT of the San Juan Basin Royalty Trust. The report includes a copy of the Trust’s Annual Report on Form 10-K filed with the Securities and Exchange Commission (the “Commission”) for the year ended December 31, 2006, without exhibits. The Form 10-K contains important information concerning the Underlying Properties, as defined below, including the oil and gas reserves attributable to the 75% net overriding royalty interest owned by the Trust. Production figures provided in this letter and in the Trustee’s Discussion and Analysis are based on information provided by Burlington Resources Oil & Gas Company LP (“BROG”), the current owner of the Underlying Properties and the successor, through a series of assignments and mergers, to Southland Royalty Company (“Southland”). 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 Trust was established in November 1980 by Southland. Pursuant to the Indenture that governs the operations of the Trust, Southland conveyed to the Trust a 75% net overriding royalty interest (equivalent to a net profits interest) (the “Royalty”), carved out of Southland Royalty’s oil and gas leasehold and royalty interests (the “Underlying Properties”) in properties in the San Juan Basin of northwestern New Mexico.
The Royalty constitutes the principal asset of the Trust. Under the Indenture governing the Trust, the function of Compass Bank, as 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. Income distributed to Unit holders in 2006 was $135,867,325 or $2.915055 per Unit. Distributable Income (as hereinafter defined) for 2006 consisted of Royalty Income of $136,311,892 plus interest income of $1,207,360, less administrative expenses of $1,651,927. Information about the Trust’s estimated proved reserves of gas, including coal seam gas, and of oil as well as the present value of net revenues discounted at 10% can be found in Item 2 of the accompanying Form 10-K. Independent petroleum engineers retained by the Trust have estimated the Underlying Properties could remain productive well beyond the stated production index of approximately 9.8 years and BROG has published information observing that the San Juan Basin will remain a major gas resource for decades to come. In support of this observation, BROG cites the November 2002 U.S. Geological Survey study doubling its estimates of the gas reserves in the San Juan Basin to over 50 trillion cubic feet. Certain royalty income is generally considered portfolio income under the passive loss rules of the Internal Revenue Code. Therefore, Unit holders should generally not consider the taxable income from the Trust to be passive income in determining net passive income or loss. Unit holders should consult their tax advisors for further information. Unit holders of record will continue to receive an individualized tax information letter for each of the quarters ending March 31, June 30 and September 30, 2007, and for the year ending December 31, 2007. Unit holders owning Units in nominee name may obtain monthly tax information from the Trust’s Web site or from the Trustee upon request. For the reader’s convenience, a glossary of definitions used in this report can be found on the inside back cover. Please visit our Web site at www.sjbrt.com to access news releases, reports, Commission filings and tax information.(GRAPHICS)
         
Compass Bank, Trustee    
By:
  Lee Ann Anderson
Vice President and Senior Trust Officer 		  (LA ANDERSON LOGO)
No 3

 

 

(GRAPHIC)
No 4

 

 

Description of the Properties
The principal asset of the Trust is a 75% net overriding royalty interest (the “Royalty”) carved out of certain working, royalty and other leasehold interests (the “Underlying Properties”) owned by BROG in oil and gas properties located in the San Juan Basin, and more particularly in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. 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 and 4,616 gross (1,286 net) producing wells, including dual completions.
The Underlying Properties have historically produced gas primarily from conventional wells drilled to three major formations: the Pictured Cliffs, the Mesaverde and the Dakota, ranging in depth from 1,500 to 8,000 feet. The characteristics of these reservoirs result in the wells having very long productive lives. A production index for oil and gas properties is derived by dividing remaining reserves by current production. Based upon the reserve report prepared by the Trust’s independent petroleum engineers as of December 31, 2006, the production index for the Underlying Properties is estimated to be approximately 9.8 years. The production index is subject to change from year-to-year based on reserve revisions and production levels and is not presented as an estimate of the life expectancy of the Trust. Among the factors considered by engineers in estimating remaining reserves of natural gas is the current sales price for gas. As the sales price increases, the producer can justify expending higher lifting costs and therefore reasonably expect to recover more of the known reserves. Accordingly, as gas prices rise, the production index increases and vice versa.
In addition to gas from conventional wells, the Underlying Properties also produce gas from coal seam wells completed to the Fruitland Coal formation. The process of removing coal seam gas is often referred to as degasification or desorption. Millions of years ago, natural gas was generated in the process of coal formation and absorbed into the coal. Water later filled the natural fracture system. When the water is removed from the natural fracture system, reservoir pressure is lowered and the gas desorbs from the coal. The desorbed gas then flows through the fracture system and is produced at the well bore. The volume of formation water production typically declines with time and the gas production may increase for a period of time before starting to decline. In order to dispose of the formation water, surface facilities including pumping units are required, which results in the cost of a completed well being as much as $550,000. The price of coal seam gas is typically lower than the price of conventional gas. This is because the heating value of coal seam gas is much lower than that of conventional gas due to (a) ever increasing percentages of carbon dioxide in coal seam gas (carbon dioxide has no heating value), and (b) the absence of heavier hydrocarbons such as ethanes, propanes, and butanes which are present in conventional gas. Furthermore, the processing fees for coal seam gas are typically higher than the processing fees for conventional gas due to the cost of extracting the carbon dioxide.
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 spacing in the Fruitland Coal formation. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997.
     The Federal Energy Regulatory Commission is primarily responsible for federal regulation of natural gas. For a further discussion of gas pricing, gas purchasers, gas production and regulatory matters affecting gas production see Item 2, “Properties,” in the accompanying Form 10-K.
Trustee’s Discussion and Analysis
 
Gas and Oil Production
Total gas and oil production from the Underlying Properties for the five years ended December 31, 2006, were as follows:
                                         
    2006   2005   2004   2003   2002
 
Gas — Mcf
     40,900,570       42,867,162       44,015,816       45,202,576       46,206,297  
Mcf per Day
     112,056       117,444       120,262       123,843       126,593  
Oil — Bbls
     74,438       69,558       77,341       74,727       93,659  
Bbls per Day
     204       191       211       205       257  
No 5

 

 

Trustee’s Discussion and Analysis
 
Gas and Oil Production cont.
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. Gas and oil sales attributable to the Royalty for the past five years are summarized in the following table:
                                         
    2006   2005   2004   2003   2002
 
Gas — Mcf
     22,475,405       26,600,644       25,324,435       25,922,650       19,584,056  
Average Price (per Mcf)
   $ 6.55     $ 6.27     $ 4.68     $ 3.93     $ 2.32  
Oil — Bbls
     40,702       43,142       44,832       43,123       40,215  
Average Price (per Bbl)
   $ 61.30     $ 49.62     $ 34.81     $ 26.11     $ 20.90  
Sales volumes attributable to the Royalty are determined by dividing the net profits received by the Trust and attributable to oil and gas, respectively, by the prices received for sales volumes from the Underlying Properties, taking into consideration production taxes attributable to the Underlying Properties. Since the oil and gas sales attributable to the Royalty are based on an allocation formula dependent on such factors as price and cost, including capital expenditures, the aggregate sales amounts from the Underlying Properties may not provide a meaningful comparison to sales attributable to the Royalty.
The fluctuations in annual gas production that have occurred during these five years generally resulted from changes in the demand for gas during that time, marketing conditions, and increased capital spending to generate production from new and existing wells. Production from the Underlying Properties is influenced by the line pressure of the gas gathering systems in the San Juan Basin. As noted above, oil and gas sales attributable to the Royalty are based on an allocation formula dependent on many factors, including oil and gas prices and capital expenditures.
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 12 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 12 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 12 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 and gas receipt points. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties.
No 6

 

 

Trustee’s Discussion and Analysis
 
Royalty Income
Royalty Income consists of monthly Net Proceeds attributable to the Royalty. Royalty Income for the five years ended December 31, 2006, was determined as shown in the following table:
                                         
    2006     2005     2004     2003     2002  
 
Gross Proceeds from the Underlying Properties
                                        
 
                                        
Gas
   $ 264,428,021     $ 267,895,460     $ 204,682,365     $ 175,653,183     $ 103,349,299  
Oil
     4,561,342       3,451,115       2,670,763       1,938,972       1,863,827  
Other
     1,384,848 1     2,405,486 2     3,314,808 3     (1,202,368 )4     (5,110,589 )5
 
                              
TOTAL
   $ 270,374,211     $ 273,752,061     $ 210,667,936     $ 176,389,787     $ 100,102,537  
 
                              
 
                                        
Less Production Costs
                                        
 
                                        
Capital Expenditures
   $ 39,195,168     $ 19,127,698     $ 22,338,684     $ 20,590,704     $ 21,470,777  
Severance Tax — Gas
     25,652,907       26,717,315       19,766,231       17,281,986       9,752,508  
Severance Tax — Oil
     460,702       362,023       253,022       174,750       151,594  
Other
     42,968       273,766       42,763       41,850       18,037  
Lease Operating Expenses and Property Taxes
     23,273,276       22,126,907       20,210,213       15,637,481       15,701,740  
 
                              
TOTAL
   $ 88,625,021     $ 68,607,709     $ 62,610,913     $ 53,726,771     $ 47,094,656  
 
                              
 
                                        
Excess Production Costs
                                        
Interest on Excess
     -0-       -0-       -0-       -0-       (2,259,628 )6
Production Costs
     -0-       -0-       -0-       -0-       (10,545 )6
Net Profits
   $ 181,749,190     $ 205,144,352     $ 148,057,023     $ 122,663,016     $ 50,737,708  
Net Overriding                                        
Royalty Interest
     75 %     75 %     75 %     75 %     75 %
Royalty Income
   $ 136,311,892     $ 153,858,264     $ 111,042,767     $ 91,997,262     $ 38,053,281  
 
                              
 
(1)   Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions, and a portion of the arbitration award issued November 11, 2005 in favor of the Trust.
 
 
(2)   Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions.
 
(3)   Represents funds allocated to the Trust as part of the ongoing negotiation of joint interest audit exceptions, interest received for resolved audit exceptions, and insurance proceeds for a bus ness interruption claim.
 
(4)   Represents a settlement between BROG and the Mineral Management Service of the United States Department of the Interior (the “MMS”).
 
(5)   Represents deductions by BROG from the net proceeds otherwise payable to the Trust in connection with the portion of various settlement agreements with the MMS.
 
(6)   RePresents excess production costs incurred in December 2001 and recovered by BROG in 2002, plus interest.
Distributable Income
“Distributable Income” (as that term is used herein) consists of Royalty Income plus interest, less the general and administrative expenses of the Trust and any changes in cash reserves established by the Trustee.
For the year ended December 31, 2006, Distributable Income was $135,867,325, representing a 10% decrease from 2005. For the year ended December 31, 2005, Distributable Income was $151,560,081, representing a 38% increase from 2004. Distributable Income in 2004 was $109,390,735.
The Trust received Royalty Income of $136,311,892 and interest income of $1,207,360 in 2006. After deducting administrative expenses of $1,651,927, Distributable Income for 2006 was $135,867,325 ($2.915055 per Unit). In 2005, Royalty Income was $153,858,264, interest income was $167,367, and administrative expenses were $2,465,550, resulting in Distributable Income of $151,560,081 ($3.251747 per Unit). Although the average gas price increased from $6.25 per Mcf for 2005 to $6.47 per Mcf for 2006, the 10% decrease in Distributable Income from 2005 to 2006 was primarily attributable to an approximately $20 million increase in capital expenditures in 2006 as compared to 2005. Interest earnings in 2006 were higher, as compared to 2005, primarily due to additional interest received in July as partial payment of the Arbitration Award described in

No 7

 

Trustee’s Discussion and Analysis
 
Note 7 to the financial statements included herewith. Administrative expenses were lower in 2006, as compared to 2005. Higher expenses were incurred in 2005 primarily as a result of compliance with the new internal control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002, costs incurred in resolving certain outstanding audit issues and obtaining the Arbitration Award.
In 2004, the Trust received Royalty Income of $111,042,767 and interest income of $58,885. After deducting administrative expenses of $1,710,917, Distributable Income for 2004 was $109,390,735 ($2.346998 per Unit). The 38% increase in Distributable Income from 2004 to 2005 was primarily attributable to higher gas and oil prices which resulted in increased Royalty Income. In addition, interest earnings in 2005 were higher, as compared to 2004, primarily due to an increase in funds available for investment as well as an increase in interest rates. Administrative expenses were higher in 2005, as compared to 2004, primarily as a result of compliance with the new internal control, financial reporting and other requirements of the Sarbanes-Oxley Act of 2002, costs incurred in resolving certain outstanding audit issues and obtaining the Arbitration Award.
BROG has informed the Trustee that the New Mexico Oil and Gas Proceeds Withholding Tax Act (the “Withholding Tax Act”) requires remitters who pay certain oil and gas proceeds from production on New Mexico properties on or after October 1, 2003, to withhold income taxes from such proceeds in the case of certain nonresident recipients. The Trustee, on advice of New Mexico counsel, has observed that “net profits interests,” such as the Royalty, and other types of interests, the extent of which cannot be determined with respect to a specific share of the oil and gas production, are excluded from the withholding requirements of the Withholding Tax Act. Unit holders are reminded to consult with their tax advisors regarding the applicability of New Mexico income tax to distributions received from the Trust by a Unit holder.
Operating Expenses
Monthly operating expenses of the Underlying Properties, exclusive of property taxes, in 2006 averaged approximately $1,871,974, which is higher than the $1,769,538 average in 2005 and higher than the $1,639,670 average in 2004. Operating expenses have increased primarily because increased activity strained the capacity of service vendors and resulted in increasing costs.
Settlements
As part of the September 4, 1996, settlement of the litigation filed by the Trustee on June 4, 1992 against BROG and Southland, the Trust was entitled to certain adjustments (the “Val Verde Credit”) that represented cost reductions favorable to the Trust in the charges for coal seam gas gathered and treated on BROG’s Val Verde system. Effective July 1, 2002, BROG sold the Val Verde facility. Accordingly, effective July 1, 2002, the calculation of net proceeds for gas gathered and treated at the Val Verde facility no longer includes the Val Verde Credit. The total amount of the Val Verde Credit for the 12 months’ ended June 30, 2002, was estimated by the Trust’s joint interest auditors as approximately $1,880,000. The loss of the Val Verde Credit resulted in increased costs allocated to the Trust for coal seam gas gathered and treated on the Val Verde system and accordingly, decreased the Royalty Income received by the Trust.
As a part of that same litigation settlement, the Trustee and BROG established a formal protocol pursuant to which joint interest auditors retained by the Trustee gained improved access to BROG’s books and records as applicable to the Underlying Properties. The audit process was initiated in 1996 and, since inception, has resulted in audit exceptions being granted by and payments or credits received from BROG totaling approximately $21,600,000.
Capital Expenditures
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 (0.48 net) coal seam recompletions, and two gross (0.08 net) coal seam miscellaneous capital projects.
There were 100 gross (26.27 net) conventional wells, 14 gross (0.39 net) payadds, seven gross (3.49 net) recompletions, six gross (4.02 net) restimulations, four gross (0.02 net) miscellaneous capital projects, 28 gross (11.79 net) coal seam wells, one gross (0.04 net) coal seam payadd, five gross (3.57 net) coal seam recompletions, and two gross (0.004 net) coal seam restimulations in progress as of December 31, 2006.
The aggregate capital expenditures reported by BROG in calculating Royalty Income for 2006 include approximately

No 8

 

Trustee’s Discussion and Analysis
 
$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 used 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 used 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 (o.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.
During 2004, in calculating Royalty Income, 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 (0.05 net) miscellaneous coal seam capital projects and facilities maintenance. There were 57 gross (6.94 net) new conventional wells, recompletion of three gross (0.89 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 (0.27 net) miscellaneous coal seam capital projects in progress as of December 31, 2004.
BROG has informed the Trust that its budget for capital expenditures for the Underlying Properties in 2007 is estimated at $28 million. Approximately $24 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 10 wells scheduled to be dually completed in the Fruitland Coal and Pictured Cliffs formations. BROG indicates that 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, the mix of projects and swings in the price of natural gas, the actual capital expenditures for 2007 could range from $20 million to $50 million.
Contractual Obligations
Under the Indenture governing the Trust, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee’s standard hourly rates (currently ranging from $75.00 to $250.00 per hour) for time in excess of 300 hours annually. As of January 1, 2003, the administrative fee due under items (i) and (ii) above will not be less than $36,000 per year (as adjusted annually to reflect the increase (if any) in the Producers Price Index as published by the U.S. Department of Labor, Bureau of Labor Statistics).
Effects of Securities Regulation
As a publicly-traded trust listed on the New York Stock Exchange (the “NYSE”), the Trust is and will continue to be subject to extensive regulation under, among others, the Securities Act of 1933, the Securities Exchange Act of 1934 (which contains many of the provisions of the Sarbanes-Oxley Act of 2002) and the rules and regulations of the NYSE. Issuers failing to comply with such authorities risk serious consequences, including criminal as well as civil and administrative penalties.

No 9

 

Trustee’s Discussion and Analysis
 
In most instances, these laws, rules and regulations do not specifically address their applicability to publicly-traded trusts, such as the Trust. In particular, the Sarbanes-Oxley Act of 2002 provides for the adoption by the Securities and Exchange Commission (the “Commission”) and NYSE of certain rules and regulations that may be impossible for the Trust to literally satisfy because of its nature as a pass-through trust. It is the Trustee’s intention to follow the Commission’s and NYSE’s rulemaking closely, attempt to comply with such rules and regulations and, where appropriate, request relief from these rules and regulations. However, if the Trust is unable to comply with such rules and regulations or to obtain appropriate relief, the Trust may be required to expend as yet unknown but potentially material costs to amend the Indenture that governs the Trust to allow for compliance with such rules and regulations. To date, the rules implementing the Sarbanes-Oxley Act of 2002 have generally made appropriate accommodation for passive entities such as the Trust.
Critical Accounting Policies
In accordance with the Commission’s staff accounting bulletins and consistent with other royalty trusts, the financial statements of the Trust are prepared on the following basis:
•   Royalty Income recorded for a month is the amount computed and paid by BROG to the Trustee for the Trust. Royalty Income consists of the proceeds received by BROG from the sale of production from the Underlying Properties less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty Income paid to the Trust and the distribution to Unit holders for that month.
 
•   Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies.
 
•   Distributions to Unit holders are recorded when declared by the Trustee.
 
•   The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over gross proceeds from such properties must be recovered from future net profits before Royalty Income is again paid to the Trust.
The financial statements of the Trust differ from financial statements prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus instead of an expense.
(GRAPHICS)
(GRAPHICS)

No 10

 

Trustee’s Discussion and Analysis
 
Results of the 4TH Ruarters of 2006 & 2005
For the three months ended December 31, 2006, Distributable Income was $26,356,915 ($.565491 per Unit), which was less than the $46,012,856 ($.987214 per Unit) of income distributed during the same period in 2005. The decrease in Distributable Income resulted primarily from lower average gas prices.
Royalty Income of the Trust for the fourth quarter is based on actual gas and oil production during August through October of each year. Gas and oil sales for the quarters ended December 31, 2006 and 2005 were as follows:
                 
    2006   2005
 
Underlying Properties
                
 
                
Gas — Mcf
     9,782,562       10,248,571  
Mcf per Day
     106,332       111,398  
Average Price (per Mcf)
   $ 5.49     $ 7.77  
Oil — Bbls
     14,992       16,477  
Bbls per Day
     163       179  
Average Price (per Bbl)
   $ 60.72     $ 59.06  
 
                
Attributable to the Royalty
                
 
                
Gas — Mcf
     5,156,724       6,516,096  
Oil — Bbls
     7,794       10,429  
The average price of gas decreased and the average price of oil increased in 2006 compared to the prior year. The price per barrel of oil during the fourth quarter of 2006 was $1.66 per Bbl higher than that received in the fourth quarter of 2005 due to increases in oil prices in world markets generally, including the posted price applicable to the Royalty. Gas production decreased because new production brought on line in 2006 failed to completely offset the natural decline in production from existing wells. In addition, production volumes were reduced in 2006 due to operational difficulties in the San Juan Basin, including: weather-related shut downs, pipeline maintenance work, compressor repairs and downtime at processing facilities.
Capital costs for the fourth quarter of 2006 totaled $8,436,427 compared to $4,734,866 during the same period of 2005. Lease operating expenses and property taxes for the fourth quarter of 2006 averaged $1,819,291 per month compared to $1,939,447 per month in the fourth quarter of 2005. Operating expenses were lower in the fourth quarter of 2006 than for the fourth quarter of 2005 primarily because in calculating Royalty Income for December 2006, BROG included a deduction of $583,725 from lease operating expense as a result of the granting of certain audit exceptions for the period 2003-2005.
Based on 46,608,796 Units outstanding, the per-Unit distributions during the fourth quarter of 2006 and 2005 were as follows:
                 
    2006     2005  
 
October
   $ .257200     $ .243762  
November
     .210820       .334553  
December
     .097471       .408899  
 
            
QUARTER TOTAL
   $ .565491     $ .987214  
 
            

No 11

 

(GRAPHICS)

 

 

San Juan Basin Royalty Trust
Statements of Assets, Liabilities and Trust Corpus
December 31, 2006 and 2005
                 
    2006     2005  
 
Assets
                
Cash and Short-Term Investments
   $ 4,657,886     $ 19,173,162  
Net Overriding Royalty Interests in Producing Oil and gas Properties — Net
     21,823,390       23,881,494  
 
            
TOTAL
   $ 26,481,276     $ 43,054,656  
 
            
                 
    2006     2005  
 
Liabilities and Trust Corpus
                
Distribution Payable to Unit holders
   $ 4,543,028     $ 19,058,304  
Cash Reserves
     114,858       114,858  
Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding
     21,823,390       23,881,494  
 
            
TOTAL
   $ 26,481,276     $ 43,054,656  
 
            
Statements of Distributable Income
For the three years ended December 31, 2006
                         
    2006     2005     2004  
 
Royalty Income
   $ 136,311,892     $ 153,858,264     $ 111,042,767  
Interest Income
     1,207,360       167,367       58,885  
 
                  
 
     137,519,252       154,025,631       111,101,652  
 
                  
Expenditures — General and Administrative
     1,651,927       2,465,550       1,710,917  
Distributable Income
   $ 135,867,325     $ 151,560,081     $ 109,390,735  
 
                  
Distributable Income per Unit (46,608,796 Units)
   $ 2.915055     $ 3.251747     $ 2.346998  
 
                  
Statements of Changes in Trust Corpus
For the three years ended December 31 ,2006
                         
    2006     2005     2004  
 
Trust Corpus, Beginning of Period
   $ 23,881,494     $ 26,674,821     $ 29,822,820  
Amortization of Net Overriding Royalty Interest
     (2,058,104 )     (2,793,327 )     (3,147,999 )
Distributable Income
     135,867,325       151,560,081       109,390,735  
Distributions Declared
     (135,867,325 )     (151,560,081 )     (109,390,735 )
 
                  
Trust Corpus, End of Period
   $ 21,823,390     $ 23,881,494     $ 26,674,821  
 
                  
These financial statements should be read in conjunction with the accompanying Notes to Financial Statements included herein.
No 13

 

 

Notes to Financial Statements
1. Trust Organization And Provisions
The San Juan Basin Royalty Trust (“Trust”) was established as of November 1, 1980. Southland Royalty Company (“Southland”) conveyed to the Trust a 75% net overriding royalty interest (“Royalty”) carved out of Southland’s working interests and royalty interests (the “Underlying Properties”) in the properties located in the San Juan Basin of northwestern New Mexico. Through an acquisition completed March 24, 2006, Compass Bank succeeded TexasBank as “Trustee” (herein so called) of the Trust. 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.
On November 3, 1980, units of beneficial interest (“Units”) in the Trust were distributed to the Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland common stock held. The Units are traded on the New York Stock Exchange.
The terms of the Trust Indenture provide, among other things, that:
•   The Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust;
 
•   The Trustee may not sell all or any part of the Royalty unless approved by holders of 75% of all Units outstanding in which case the sale must be for cash and the proceeds promptly distributed;
 
•   The Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount;
 
•   The Trustee is authorized to borrow funds to pay liabilities of the Trust; and
 
•   The Trustee will make monthly cash distributions to Unit holders (see Note 2).
2. Net Overriding Royalty Interest And Distribution To Unit Holders
The amounts to be distributed to Unit holders (“Monthly Distribution Amounts”) are determined on a monthly basis by the Trustee. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalty, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month and such negative amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or before 10 business days after the monthly record date, which is generally the last business day of each calendar month.
The cash received by the Trustee consists of the proceeds received by the owner of the Underlying Properties from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75%.
The initial carrying value of the Royalty ($133,275,528) represented Southland’s historical net book value at the date of the transfer of the Trust. Accumulated amortization as of December 31, 2006 and 2005 aggregated $111,452,138 and $109,394,034, respectively.
3. Basis Of Accounting
The financial statements of the Trust are prepared on the following basis:
•   Royalty Income (as defined in the Glossary of Terms) recorded for a month is the amount computed and paid by the owner of the Underlying Properties, Burlington Resources Oil & Gas Company LP (“BROG”), the present owner of the Underlying Properties, to the Trustee for the Trust. Royalty Income consists of the proceeds received by BROG from the sale of production less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. The calculation of net proceeds by BROG for any month includes adjustments to proceeds and costs for prior months and impacts the Royalty Income paid to the Trust and the distribution to Unit holders for that month.
•   Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty Income for liabilities and contingencies.
 
•   Distributions to Unit holders are recorded when declared by the Trustee.
 
•   The conveyance which transferred the Royalty to the Trust provides that any excess of production costs applicable to the Underlying Properties over gross
No 14

 

Notes to financial Statements
proceeds from such properties must be recovered from future net proceeds before Royalty Income is again paid to the Trust.
The financial statements of the Trust differ from financial statements prepared in accordance with United States generally accepted accounting principles (“GAAP”) because revenues are not accrued in the month of production; certain cash reserves may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP; expenses are recorded when paid instead of when incurred; and amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus instead of an expense. The basis of accounting used by the Trust is widely used by royalty trusts for financial purposes.
4. Federal Income Taxes
For federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit holders are considered to own the Trust’s income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust.
The Royalty constitutes an “economic interest” in oil and gas properties for federal income tax purposes. Unit holders must report their share of the revenues of the Trust as ordinary income from oil and gas royalties and are entitled to claim depletion with respect to such income. The Royalty is treated as a single property for depletion purposes. The Trust has on file technical advice memoranda confirming such tax treatment.
Sales of gas production from 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.
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.
5. Certain Contracts
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 12 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 12 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 have entered into a letter agreement dated January 31, 2005, pursuant to which the parties waive the right to terminate the underlying contract as of March 31, 2006, so that the term of that contract will continue until at least March 31, 2007, and from year-to-year thereafter until terminated by either party upon 12 months’ notice to the
No 15

 

 

Notes to financial Statements
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 and gas receipt points. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties.
6. Significant Customers
Information as to significant purchasers of oil and gas production attributable to the Trust’s economic interests is included in Note 5 above and Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.
7. Settlements and Litigation
During 2004, an aggregate of $3,314,808 was included in calculating net proceeds paid to the Trust by BROG as part of the ongoing negotiation of joint interest audit exceptions, interest for resolved audit exceptions, and insurance proceeds for a business interruption claim.
In 2005, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, an aggregate of $2,405,486 was included in calculating net proceeds BROG paid to the Trust in settlement of certain of those audit issues.
During 2006, as part of the ongoing negotiations between the Trust and BROG concerning a number of revenue and expense audit issues, an aggregate of $1,981,933 was included in calculating net proceeds paid to the Trust, together with interest of $1,124,063 in settlement of certain of those audit issues.
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 cause styled Burlington Resources Oil & Gas Company LP vs. San Juan Basin Royalty Trust, No. 2005-74370, in the District Court of Harris County, Texas, 281st 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 and 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.
8. Proved Oil and Gas Reserves (unaudited)
Proved oil and gas reserve information is included in Item 2 of the Trust’s Annual Report on Form 10-K which is included in this report.
No 16

 

 

9. Quarterly Schedule Of Distributable Income (unaudited)
The following is a summary of the unaudited quarterly schedule of Distributable Income for the two years ended December 31, 2006 (in thousands, except unit amounts):
                         
                    DISTRIBUTABLE  
    ROYALTY     DISTRIBUTABLE     INCOME AND  
    INCOME     INCOME     DISTRIBUTION PER UNIT  
2006
                        
First Quarter
   $ 50,481     $ 50,490     $ 1.083276  
Second Quarter
     28,532       27,933       .599299  
Third Quarter
     30,780       31,087       .666989  
Fourth Quarter
     26,519       26,357       .565491  
 
                  
TOTAL
   $ 136,312     $ 135,867     $ 2.915055  
 
                  
 
                        
2005
                        
First Quarter
   $ 39,242     $ 38,736     $ .831092  
Second Quarter
     35,296       34,519       .740612  
Third Quarter
     32,833       32,292       .692829  
Fourth Quarter
     46,487       46,013       .987214  
TOTAL
   $ 153,858     $ 151,560     $ 3.251747  
 
                  
Report of Independent Registered Public Accounting Firm
WE HAVE AUDITED THE ACCOMPANYING STATEMENTS of assets, liabilities and trust corpus of the San Juan Basin Royalty Trust 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. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits 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 the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
As described in Note 3 to the financial statements, these financial statements were prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than U.S. generally accepted accounting principles.
In our opinion, the financial statements referred to above present fairly, in all material respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 2006 and 2005 and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2006, on the basis of accounting described in Note 3 to the financial statements.
We have also audited in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness of the Trust’s 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 and our report dated February 28, 2007, expressed an unqualified opinion thereon.
     
Weaver and Tidwell, L.L.P.    
     
Fort Worth, Texas    
February 28, 2007   (WEAVER AND TIDWELL, L.L.P.)

No 17

 

Glossary of Terms
Aggregate Monthly Distribution: An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a calendar month plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves.
BBL: Barrel, generally 42 U.S. gallons measured at 60°F.
BCF: Billion cubic feet.
BROG: Burlington Resources Oil & Gas Company LP.
BTU: British thermal unit; the amount of heat necessary to raise the temperature of one pound of water one degree Fahrenheit.
Coal Seam Well: A well completed to a coal deposit found to contain and emit natural gas.
Commingled Well: A well which produces from two or more formations through a common well casing and a single tubing string.
Conventional Well: A well completed to a formation historically found to contain deposits of oil or gas (for example, in the San Juan Basin, the Pictured Cliffs, Dakota and Mesaverde formations) and operated in the conventional manner.
Depletion: The exhaustion of a petroleum reservoir; the reduction in value of a wasting asset by removing minerals; for tax purposes, the removal and sale of minerals from a mineral deposit.
Distributable Income: An amount paid to Unit holders equal to the Royalty Income received by the Trustee during a given period plus interest, less the general and administrative expenses of the Trust, adjusted by any changes in cash reserves.
Dual Completion: The completion of a well into two separate producing formations at different depths, generally through one string of pipe producing from one of the formations, inside of which is a smaller string of pipe producing from the other formation.
Estimated Future Net Revenues: An estimate 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; sometimes referred to as “estimated future net cash flows.”
Grantor Trust: A trust (or portion thereof) with respect to which the grantor or an assignee of the grantor, rather than the trust, is treated as the owner of the trust properties and is taxed directly on the trust income for federal income tax purposes under Sections 671 through 679 of the Internal Revenue Code of 1986, as amended.
Gross Acres or Wells: The interests of all persons owning interests in such acres or wells.
Gross Proceeds: The amount received by BROG (or any subsequent owner of the Underlying Properties) from the sale of the production attributable to such interests.
Infill Drilling: The drilling of wells intended to be completed to proven reservoirs or formations, sometimes occurring in conjunction with regulatory approval for increased density in the spacing of wells.
Lease Operating Expenses: Expenses incurred in the operation of a producing property as apportioned among the several parties in interest.
MCF: 1,000 cubic feet; the standard unit for measuring the volume of natural gas.
MMBTU: One million British thermal units.
Multiple Completion Well: A well which produces simultaneously through separate tubing strings from two or more producing horizons or alternatively from each.
Net Acres or Wells: The interests of BROG in such acres or wells.
Net Overriding Royalty Interest: A share of gross production from a property, measured by net profits from operation of the property and carved out of the working interest, i.e., a net profits interest.
Net Proceeds: The excess of Gross Proceeds received by BROG during a particular period over Production Costs for such period.
Payadd: Completion in an existing well of additional productive zone(s) within a producing formation.
Present Value Of Estimated Future Net Revenues: The present value of the Estimated Future Net Revenues computed using a discount rate of 10%.
Production Costs: Costs incurred on an accrual basis by BROG in operating the Underlying Properties, including both capital and non-capital costs and including, for example, development drilling, production and processing costs, applicable taxes and operating charges.
Proved Developed Reserves: Those Proved Reserves which can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved Reserves: 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 Undeveloped Reserves: 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.
Recavitated Well: A coal seam well, the production from which has been enhanced or extended by the enlargement of the cavity within the coal deposit to which the well has been completed.
Recompleted Well: A well completed by drilling a separate well bore from an existing casing in order to reach the same reservoir, or re-drilling the same well bore to reach a new reservoir after production from the original reservoir has been abandoned.
Royalty: The principal asset of the Trust; the 75% net overriding royalty interest conveyed to the Trust on November 3,1980, by Southland Royalty Company, the predecessor to BROG, which was carved out of the Underlying Properties.
Royalty Income: The monthly Net Proceeds attributable to the Royalty.
Section 45K tax credit: A Federal income tax credit available under Section 45K of the Internal Revenue Code of 1986, as amended, for coal seam gas (and certain other nonconventional fuels) that was (i) sold prior to January 1, 2003 and (ii) produced from wells drilled (or certain later recompletions treated as wells drilled) after December 31,1979, but prior to January 1, 1993.
Spot Price: The price paid for gas, oil or oil products sold under contracts for the purchase and sale of such minerals on a short-term basis.
Underlying Properties: The working, royalty and other interests owned by Southland Royalty Company, the predecessor to BROG, in properties located in the San Juan Basin of northwestern New Mexico, out of which the Royalty was carved.
Units of Beneficial Interest: The units of ownership of the Trust, equal to the number of shares of common stock of Southland Royalty Company outstanding at the close of business on November 3,1980.
Working Interest: The operating interest under an oil and gas lease.

 

 

(GRAPHIC)
san juan royalty trust
Campass Bank, Trustee
2525 Ridgmar Boulevard, Suite 100 ~S.CONT Fort Worth, Texas 76116 Toll-free telephone: 966.809.4553 www.sjbrt.com sjt@compassbank.com
auditors Weaver and Tidwell, L.L.P. Dallas, Texas
transfer Agent Computershare Investor Services P.O. Box 43078 Providence, RI 02940-43078 www.computershare.com
for question about distribution checks, address change, and transfer providers call 312-360-5154

 

EX-23 4 d44062exv23.htm CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC. exv23
 

Exhibit 23
[Cawley, Gillespie & Associates, Inc., letterhead]
 
March 1, 2007
 
 
San Juan Basin Royalty Trust
 Compass Bank, Trustee
2525 Ridgmar Boulevard, Suite 100
Fort Worth, Texas 76116
 
 
Ladies and Gentlemen:
 
Cawley, Gillespie & Associates, Inc. hereby consents to the use of the oil and gas reserve information in the San Juan Basin Royalty Trust Securities & Exchange Commission Form 10-K for the year ended December 31, 2006 and in the San Juan Basin Royalty Trust Annual Report for the year ended December 31, 2006 based on reserve reports prepared by Cawley, Gillespie & Associates, Inc. and dated March 1, 2007.
 
Sincerely,
 
/s/  Cawley, Gillespie & Associates, Inc.
CAWLEY, GILLESPIE & ASSOCIATES, INC.

EX-31 5 d44062exv31.htm CERTIFICATION REQUIRED BY RULE 13A-14(A) exv31
 

Exhibit 31
 
CERTIFICATION
 
I, Lee Ann Anderson, certify that:
 
1. I have reviewed this Annual Report on Form 10-K of San Juan Basin Royalty Trust, for which Compass Bank acts as Trustee;
 
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
 
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the periods presented in this report;
 
4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and I have:
 
a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under my supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this report is being prepared;
 
b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under my supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes;
 
c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report my conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
 
5. I have disclosed, based on my most recent evaluation of internal control over financial reporting, to the registrant’s auditors:
 
a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b) Any fraud, whether or not material, that involves persons who have a significant role in the registrant’s internal control over financial reporting.
 
In giving the certifications in paragraphs 4 and 5 above, I have relied to the extent I consider reasonable on information provided to me by Burlington Resources Oil & Gas Company LP.
 
  By: 
/s/  Lee Ann Anderson
Lee Ann Anderson
Vice President and Senior Trust Officer,
Compass Bank
 
Date: March 1, 2007

EX-32 6 d44062exv32.htm CERTIFICATION REQUIRED BY RULE 13A-14(B) exv32
 

Exhibit 32
 
CERTIFICATION OF
THE TRUSTEE*
OF THE SAN JUAN BASIN ROYALTY TRUST
PURSUANT TO 18 U.S.C. § 1350
 
In connection with the accompanying report on Form 10-K for the year ended December 31, 2006, and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Lee Ann Anderson, Vice President and Senior Trust Officer of Compass Bank, on behalf of Compass Bank, the Trustee of the San Juan Basin Royalty Trust (the “Trust”), not in its individual capacity but solely as Trustee of the Trust, hereby certify that:
 
1. The Report fully complies in all material respects with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (as explained in Note 3 to the Trust’s financial statements contained in the Trust’s Annual Report to Unit Holders for the year ended December 31, 2006, attached as Exhibit 13 to the Report, in accordance with Securities and Exchange Commission Staff Accounting Bulletin No. 47, released September 16, 1982, the Trust prepares its financial statements in a manner that differs from generally accepted accounting principles; such presentation is customary to other royalty trusts); and
 
2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Trust.
 
COMPASS BANK, AS TRUSTEE OF THE
SAN JUAN BASIN ROYALTY TRUST
 
  By: 
/s/  Lee Ann Anderson
Name: Lee Ann Anderson
Title: Vice President and Senior Trust Officer
 
Date: March 1, 2007
 
 
* The Trust has no executive officers.

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