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Permian Basin Royalty Trust · 10-K · For 12/31/05

Filed On 3/15/06, 4:07pm ET   ·   Accession Number 950134-6-5169   ·   SEC File 1-08033

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  As Of                Filer                Filing    For/On/As Docs:Size              Issuer               Agent

 3/15/06  Permian Basin Royalty Trust       10-K       12/31/05    6:347K                                   Bowne of Dallas I..01/FA

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Annual Report                                       HTML    181K 
 2: EX-13       Annual Report to Security Holders                   HTML    114K 
 3: EX-23.1     Consent of Cawley, Gillespie & Associates, Inc.     HTML      8K 
 4: EX-23.2     Consent of Deloitte & Touche LLP                    HTML      6K 
 5: EX-31.1     Certification Required by Rule 13A-14(A)/15D-14(A)  HTML     13K 
 6: EX-32.1     Certification Required by Rule 13A-14(B)/15D-14(B)  HTML      9K 
                          and Section 906                                        


10-K   —   Annual Report
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
"Table of Contents
"Part I
"Item 1. Business
"Item 1A. Risk Factors
"Item 1B. Unresolved Staff Comments
"Item 2. Properties
"Item 3. Legal Proceedings
"Item 4. Submission of Matters to a Vote of Security Holders
"Part Ii
"Item 5. Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units
"Item 6. Selected Financial Data
"Item 7. Management'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
"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
"Item 13. Certain Relationships and Related Transactions
"Item 14. Principal Accounting Fees and Services
"Part Iv
"Item 15. Exhibits, Financial Statement Schedules
"Signature
"Index to Exhibits

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Table of Contents

 
 
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, 2005
OR
     
o   TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission file number 1-8033
PERMIAN BASIN ROYALTY TRUST
(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust Indenture)
     
Texas
(State or Other Jurisdiction of
Incorporation or Organization)
  75-6280532
(I.R.S. Employer Identification No.)
Bank of America, N.A.
Trust Department
P.O. Box 830650
Dallas, Texas 75202
(Address of Principal Executive Offices; Zip Code)

(Registrant’s Telephone Number, Including Area Code)
(214) 209-2400
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
     Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ
     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. o
     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 Exchange Act.
Large accelerated filer [ ]                     Accelerated filer [X]                     Non-accelerated filer [ ]
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ
     The aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter was $288,701,104.
     At March 1, 2006, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding.
DOCUMENTS INCORPORATED BY REFERENCE
     “Units of Beneficial Interest” at page 1; “Trustee’s Discussion and Analysis for the Three-Year Period Ended December 31, 2005 at pages 7 through 11; “Results of the 4th Quarters of 2005 and 2004” at page 10; 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 12 et seq., in registrant’s Annual Report to security holders for fiscal year ended December 31, 2005 are incorporated herein by reference for Item 5, Item 7 and Item 8 of Part II of this Report.
 
 

 



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FORWARD LOOKING INFORMATION
     Certain information included in this report contains, and other materials filed or to be filed by the Trust with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended, and Section 27A of the Securities Act of 1933, as amended. Such forward looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices and the results thereof, and regulatory matters. Although the Trustee believes that the expectations reflected in such forward looking statements are reasonable, such expectations are subject to numerous risks and uncertainties and the Trustee can give no assurance that they will prove correct. There are many factors, none of which is within the Trustee’s control, that may cause such expectations not to be realized, including, among other things, factors such as actual oil and gas prices and the recoverability of reserves, capital expenditures, general economic conditions, actions and policies of petroleum-producing nations and other changes in the domestic and international energy markets and the factors identified under Item 1A, “Risk Factors.” Such forward looking statements generally are accompanied by words such as “estimate,” “expect,” “anticipate,” “goal,” “should,” “assume,” “believe,” or other words that convey the uncertainty of future events or outcomes.

 



 


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Registrant’s Annual Report
   
Consent of Cawley, Gillespie & Associates, Inc.
   
Certification Required by Rule 13a-14(a)/15d-14(a)
   
Certification Required by Rule 13a-14(a)/15d-14(b) and Section 906
     
 Annual Report to Security Holders
 Consent of Cawley, Gillespie & Associates, Inc.
 Consent of Deloitte & Touche LLP
 Certification Required by Rule 13a-14(a)/15d-14(a)
 Certification Required by Rule 13a-14(b)/15d-14(b) and Section 906

 



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PART I

Item 1. Business
     The Permian Basin Royalty Trust (the “Trust”) is an express trust created under the laws of the state of Texas by the Permian Basin Royalty Trust Indenture (the “Trust Indenture) entered into on November 3, 1980, between Southland Royalty Company (“Southland Royalty”) and The First National Bank of Fort Worth, as Trustee. Bank of America, N.A., a banking association organized under the laws of the United States, as the successor of The First National Bank of Fort Worth, is now the Trustee of the Trust. The principal office of the Trust (sometimes referred to herein as the “Registrant”) is located at 901 Main Street, Dallas, Texas (telephone number (214) 209-2400).
     On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company’s conveyance of net overriding royalty interests (equivalent to net profits interests) 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 consisting of a 75% net overriding royalty interest carved out of that company’s fee mineral interests in the Waddell Ranch properties in Crane County, Texas and a 95% net overriding royalty interest carved out of that company’s major producing royalty properties in Texas. The conveyance of these interests (the “Royalties”) was made on November 3, 1980, effective as to production from and after November 1, 1980 at 7:00 a.m. The properties and interests from which the Royalties were carved and which the Royalties now burden are collectively referred to herein as the “Underlying Properties.” The Underlying Properties are more particularly described under “Item 2. Properties” herein.
     The function of the Trustee is to collect the income attributable to the Royalties, to pay all expenses and charges of the Trust, and then distribute the remaining available income to the Unit holders. The Trust is not empowered to carry on any business activity and has no employees, all administrative functions being performed by the Trustee.
     The Royalties constitute the principal asset of the Trust and the beneficial interests in the Royalties are divided into that number of Units of Beneficial Interest (the “Units”) of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980, received one Unit for each share of the common stock of Southland Royalty then held.
     In 1985, Southland Royalty became a wholly-owned subsidiary of Burlington Northern Inc. (“BNI”). In 1988, BNI transferred its natural resource operations to Burlington Resources Inc. (“BRI”) as a result of which Southland Royalty became a wholly-owned indirect subsidiary of BRI. As a result of this transfer, Meridian Oil Inc. (“MOI”), which was the parent company of Southland Royalty, became a wholly owned direct subsidiary of BRI. In 1996, Southland Royalty was merged with and into MOI. As a result of this merger, the separate corporate existence of Southland Royalty ceased and MOI survived and succeeded to the ownership of all of the assets of Southland Royalty and assumed all of its rights, powers, privileges, liabilities and obligations. In 1996, MOI changed its name to Burlington Resources Oil & Gas Company, now Burlington Oil & Gas Company LP (“BROG”). On December 12, 2005, BRI and ConocoPhillips announced a proposed transaction pursuant to which ConocoPhillips would acquire BRI, subject to shareholder approval by BRI.
     The term “net proceeds” is used in the above described conveyance and 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” means, generally, costs incurred on an accrual basis in operating the Underlying Properties, including both capital and non-capital costs; for example, 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 liable for any production costs or liabilities attributable to these properties and interests or the minerals produced therefrom. If at any time the Trust receives more than the

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amount due from the Royalties, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such overpaid amount, plus interest, at a rate specified in the conveyance.
     To the extent it has the legal right to do so, BROG is responsible for marketing the production from such properties and interests, 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. BROG, however, can sell its interests in the Underlying Properties.
     Proceeds from production in the first month are generally received by BROG in the second month, the net proceeds attributable to the Royalties 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. The identity of Unit holders entitled to a distribution will generally be determined as of the last business day of each calendar month (the “monthly record date”). The amount of each monthly distribution will generally be determined and announced ten days before the monthly record date. Unit holders of record as of the monthly record date will be entitled to receive the calculated monthly distribution amount for each month on or before ten business days after the monthly record date. The aggregate monthly distribution amount is the excess of (i) net revenues from the Trust properties, plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the Trust over (ii) the expenses and payments of liabilities of the Trust plus any net increase in cash reserves for contingent liabilities.
     Cash 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, at 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, or certificates of deposit of banks having a capital surplus and undivided profits in excess of $50,000,000, subject, in each case, to certain other qualifying conditions.
     The income to the Trust attributable to the Royalties is not subject in material respects to seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities. The Trust has no employees since all administrative functions are performed by the Trustee.
     BROG has advised the Trustee that it believes that comparable revenues could be obtained in the event of a change in purchasers of production.
Website/SEC Filings
     Our Internet address is http://www.pbt-permianbasintrust.com. You can review, free of charge, the filings the Trust has made with respect to its annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934. We shall post these reports as soon as reasonably practicable after we electronically file them with, or furnish them to the SEC.

Item 1A. Risk Factors
Crude oil and natural gas prices are volatile and fluctuate in response to a number of factors; Lower prices could reduce the net proceeds payable to the Trust and Trust distributions.
     The Trust’s monthly distributions are highly dependent upon the prices realized from the sale of crude oil and natural gas and a material decrease in such prices could reduce the amount of cash distributions paid to Unit holders. Crude oil and natural 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. Factors that contribute to price fluctuation include, among others:

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    political conditions in major oil producing regions, especially in the Middle East;
 
    worldwide economic conditions;
 
    weather conditions;
 
    the supply and price of domestic and foreign crude oil or natural gas;
 
    the level of consumer demand;
 
    the price and availability of alternative fuels;
 
    the proximity to, and capacity of, transportation facilities;
 
    the effect of worldwide energy conservation measures; and
 
    the nature and extent of governmental regulation and taxation.
     When crude oil and natural gas prices decline, the Trust is affected in two ways. First, net income from the Royalties is reduced. Second, exploration and development activity on the Underlying Properties may decline as some projects may become uneconomic and are either delayed or eliminated. It is impossible to predict future crude oil and natural gas price movements, and this reduces the predictability of future cash distributions to Unit holders.
Increased production and development costs attributable to the Royalties will result in decreased Trust distributions unless revenues also increase.
     Production and development costs attributable to the Royalties are deducted in the calculation of the Trust’s share of net proceeds. Accordingly, higher or lower production and development costs will directly decrease or increase the amount received by the Trust from the Royalties. For example, the costs of electricity that will be included in production and development costs deducted in calculating the Trust’s share of 2006 net proceeds could increase compared to the electrical costs incurred during 2005 principally as a result of higher fuel surcharges which could be charged by the third party electricity provider in response to the higher costs of natural gas consumed to generate the electricity. These increased costs could reduce the Trust share of 2006 net proceeds below the level that would exist if such costs remained at the level experienced in 2005. If production and development costs attributable to the Royalties exceed the gross proceeds related to production from the Underlying Properties, the Trust will not receive net proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest during the deficit period. Development activities may not generate sufficient additional proceeds to repay the costs.
Trust reserve estimates depend on many assumptions that may prove to be inaccurate, which could cause both estimated reserves and estimated future net revenues to be too high, leading to write-downs of estimated reserves.
     The value of the Units will depend upon, among other things, the reserves attributable to the Royalties from the Underlying Properties. The calculations of proved reserves and estimating reserves is inherently uncertain. In addition, the estimates of future net revenues are based upon various assumptions regarding future production levels, prices and costs that may prove to be incorrect over time.
     The accuracy of any reserve estimate is a function of the quality of available data, engineering interpretation and judgment, and the assumptions used regarding the quantities of recoverable crude oil and natural gas and the future prices of crude oil and natural gas. Petroleum engineers consider many factors and make many assumptions in estimating reserves. Those factors and assumptions include:
    historical production from the area compared with production rates from similar producing areas;

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    the effects of governmental regulation;
 
    assumptions about future commodity prices, production and development costs, taxes, and capital expenditures;
 
    the availability of enhanced recovery techniques; and
 
    relationships with landowners, working interest partners, pipeline companies and others.
     Changes in any of these factors and assumptions can materially change reserve and future net revenue estimates. The Trust’s estimate of reserves and future net revenues is further complicated because the Trust holds an interest in net overriding royalties and does not own a specific percentage of the crude oil or natural gas reserves. Ultimately, actual production, revenues and expenditures for the Underlying Properties, and therefore actual net proceeds payable to the Trust, will vary from estimates and those variations could be material. Results of drilling, testing and production after the date of those estimates may require substantial downward revisions or write-downs of reserves.
The assets of the Trust are depleting assets and, if BROG and the other operators developing the Underlying Properties do not perform additional development projects, the assets may deplete faster than expected. Eventually, the assets of the Trust will cease to produce in commercial quantities and the Trust will cease to receive proceeds from such assets. In addition, a reduction in depletion tax benefits may reduce the market value of the Units.
     The net proceeds payable to the Trust are derived from the sale of depleting assets. 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 and can offset the reduction in proved reserves. The timing and size of these projects will depend on the market prices of crude oil and natural gas. If the operators developing the Underlying Properties, including BROG, do 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.
     Because the net proceeds payable to the Trust are derived from the sale of depleting assets, the portion of distributions to Unit holders attributable to depletion may be considered a return of capital as opposed to a return on investment. Distributions that are a return of capital will ultimately diminish the depletion tax benefits available to the Unit holders, which could reduce the market value of the Units over time. Eventually, the Royalties will cease to produce in commercial quantities and the Trust will, therefore, cease to receive any distributions of net proceeds therefrom.
The market price for the Units may not reflect the value of the royalty interests held by the Trust.
     The public trading price for the Units tends to be tied to the recent and expected levels of cash distribution on the Units. The amounts available for distribution by the Trust vary in response to numerous factors outside the control of the Trust, including prevailing prices for crude oil and natural gas produced from the Royalties. The market price is not necessarily indicative of the value that the Trust would realize if it sold those Royalties to a third party buyer. In addition, such market price is not necessarily reflective of the fact that since the assets of the Trust are depleting assets, a portion of each cash distribution paid on the Units should be considered by investors as a return of capital, with the remainder being considered as a return on investment. There is no guarantee that distributions made to a Unit holder over the life of these depleting assets will equal or exceed the purchase price paid by the Unit holder.
Operational risks and hazards associated with the development of the Underlying Properties may decrease Trust distributions.
     There are operational risks and hazards associated with the production and transportation of crude oil and natural gas, including without limitation natural disasters, blowouts, explosions, fires, leakage of

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crude oil or natural gas, mechanical failures, cratering, and pollution. Any of these or similar occurrences could result in the interruption of operations, personal injury or loss of life, property damage, damage to productive formations or equipment, or damage to the environment. The uninsured costs resulting from any of these or similar occurrences would be deducted as a cost of production in calculating the net proceeds payable to the Trust and would therefore reduce Trust distributions by the amount of such uninsured costs.
Terrorism and continued hostilities in the Middle East could decrease Trust distributions or the market price of the Units.
     Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as the military or other actions taken in response, cause instability in the global financial and energy markets. Terrorism, the war in Iraq and other sustained military campaigns could adversely affect Trust distributions or the market price of the Units in unpredictable ways, including through the disruption of fuel supplies and markets, increased volatility in crude oil and natural gas prices, or the possibility that the infrastructure on which the operators developing the Underlying Properties rely could be a direct target or an indirect casualty of an act of terror.
Unit holders and the Trustee have no influence over the operations on, or future development of, the Underlying Properties.
     Neither the Trustee nor the Unit holders can influence or control the operations on, or future development of, the Underlying Properties. The failure of an operator to conduct its operations, discharge its obligations, deal with regulatory agencies or comply with laws, rules and regulations, including environmental laws and regulations, in a proper manner could have an adverse effect on the net proceeds payable to the Trust. The current operators developing the Underlying Properties are under no obligation to continue operations on the Underlying Properties. Neither the Trustee nor the Unit holders have the right to replace an operator.
The operators developing the Texas Royalty properties have no duty to protect the interests of the Unit holders, and do not have sole discretion regarding development activities on the Underlying Properties.
     Under the terms of a typical operating agreement relating to oil and gas properties, the operator owes a duty to working interest owners to conduct its operations on the properties in a good and workmanlike manner and in accordance with its best judgment of what a prudent operator would do under the same or similar circumstances. BROG is the operator of record of the Waddell Ranch overriding royalty interests and in such capacity owes the Trust a contractual duty under the conveyance agreement for that overriding royalty interest to operate the Waddell Ranch properties in good faith and in accordance with a prudent operator standard. The operators of the properties burdened by the Texas Royalty properties’ overriding royalty interests, however, have no contractual or fiduciary duty to protect the interests of the Trust or the Unit holders other than indirectly through its duty of prudent operations to the unaffiliated owners of the working interests in those properties.
     In addition, even if an operator, including BROG in the case of the Waddell Ranch properties, concludes that a particular development operation is prudent on a property, it may be unable to undertake such activity unless it is approved by the requisite approval of the working interest owners of such properties (typically the owners of at least a majority of the working interests). Even if the Trust concludes that such activities in respect of any of its overriding royalty interests would be in its best interests, it has no right to cause those activities to be undertaken.
The operator developing any Underlying Property may transfer its interest in the property without the consent of the Trust or the Unit holders.
     Any operator developing any of the Underlying Properties may at any time transfer all or part of its interest in the Underlying Properties to another party. Neither the Trust nor the Unit holders are entitled to vote on any transfer of the properties underlying the Royalties, and the Trust will not receive any proceeds of any such transfer. Following any transfer, the transferred property will continue to be subject to

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the Royalties, but the net proceeds from the transferred property will be calculated separately and paid by the transferee. The transferee will be responsible for all of the transferor’s obligations relating to calculating, reporting and paying to the Trust the Royalties from the transferred property, and the transferor will have no continuing obligation to the Trust for that property.
The operator developing any Underlying Property may abandon the property, thereby terminating the Royalties payable to the Trust.
     The operators developing the Underlying Properties, or any transferee thereof, may abandon any well or property without the consent of the Trust or the Unit holders if they reasonably believe that the well or property can no longer produce in commercially economic quantities. This could result in the termination of the Royalties relating to the abandoned well or property.
The Royalties can be sold and the Trust would be terminated.
     The Trustee must sell the Royalties if the holders of 75% or more of the Units approve the sale or vote to terminate the Trust. The Trustee must also sell the Royalties if they fail to generate net revenue for the Trust of at least $1,000,000 per year over any consecutive two-year period. Sale of all of the Royalties will terminate the Trust. The net proceeds of any sale will be distributed to the Unit holders.
Unit holders have limited voting rights and have limited ability to enforce the Trust’s rights against the current or future operators developing the Underlying Properties.
     The voting rights of 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.
     The Trust indenture and related trust law permit the Trustee and the Trust to sue BROG, Riverhill Energy Corporation or any other future operators developing the Underlying Properties to compel them to fulfill the terms of the conveyance of the Royalties. If the Trustee does not take appropriate action to enforce provisions of the conveyance, the recourse of the Unit holders would likely be limited to bringing a lawsuit against the Trustee to compel the Trustee to take specified actions. Unit holders probably would not be able to sue BROG, Riverhill Energy Corporation or any other future operators developing the Underlying Properties.
Financial information of the Trust is not prepared in accordance with GAAP.
     The financial statements of the Trust are prepared on a modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States, or GAAP. Although this basis of accounting is permitted for royalty trusts by the U.S. Securities and Exchange Commission, the financial statements of the Trust differ from GAAP financial statements because revenues are not accrued in the month of production and cash reserves may be established for specified contingencies and deducted which could not be accrued in GAAP financial statements.
The limited liability of the Unit holders in uncertain.
     The Unit holders are not protected from the liabilities of the Trust to the same extent that a shareholder would be protected from a corporation’s liabilities. The structure of the Trust does not include the interposition of a limited liability entity such as a corporation or limited partnership which would provide further limited liability protection to Unit holders. While the Trustee is liable for any excess liabilities incurred if the Trustee fails to insure that such liabilities are to be satisfied only out of Trust assets, under the laws of Texas, which are unsettled on this point, a holder of Units may be jointly and severally liable for any liability of the Trust if the satisfaction of such liability was not contractually limited to the assets of the Trust and the assets of the Trust and the Trustee are not adequate to satisfy such liability. As a result, Unit holders may be exposed to personal liability.

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Item 1B. Unresolved Staff Comments
     The Trust has not received any written comments from the Commission staff regarding its periodic or current reports under the Act within the 180 days preceding December 31, 2005.

Item 2. Properties
     The net overriding royalties conveyed to the Trust (the “Royalties”) include: (1) a 75% net overriding royalty carved out of Southland Royalty’s fee mineral interests in the Waddell Ranch in Crane County, Texas (the “Waddell Ranch properties”); and (2) a 95% net overriding royalty carved out of Southland Royalty’s major producing royalty interests in Texas (the “Texas Royalty properties”). The net overriding royalty for the Texas Royalty properties is subject to the provisions of the lease agreements under which such royalties were created. References below to “net” wells and acres are to the interests of BROG (from which the Royalties were carved) in the “gross” wells and acres.
     The following information under this Item 2 is based upon data and information, including audited computation statements, furnished to the Trustee by BROG and Riverhill.
PRODUCING ACREAGE, WELLS AND DRILLING
     Waddell Ranch Properties. The Waddell Ranch properties consist of 76,922 gross (33,246 net) producing acres. A majority of the proved reserves are attributable to six fields: Dune, Sand Hills (Judkins), Sand Hills (McKnight), Sand Hills (Tubb), University-Waddell (Devonian) and Waddell. At December 31, 2005, the Waddell Ranch properties contained 782 gross (349 net) productive oil wells, 193 gross (91 net) productive gas wells and 316 gross (137 net) injection wells.
     BROG is operator of record of the Waddell Ranch properties. All field, technical and accounting operations have been contracted by an agreement between the working interest owners and Schlumberger Integrated Project Management (IPM) but remain under the direction of BROG.
     The Waddell Ranch properties are mature producing properties, and all of the major oil fields are currently being waterflooded for the purpose of facilitating enhanced recovery. Proved reserves and estimated future net revenues attributable to the properties are included in the reserve reports summarized below. BROG does not own the full working interest in any of the tracts constituting the Waddell Ranch properties and, therefore, implementation of any development programs will require approvals of other working interest holders as well as BROG. In addition, implementation of any development programs will be dependent upon oil and gas prices currently being received and anticipated to be received in the future. There were 6 gross (3 net) wells drilled and completed on the Waddell Ranch properties during 2005. At December 31, 2005, there were no wells in progress on the Waddell Ranch properties. There were 4 gross (2 net) wells drilled and completed on the Waddell Ranch properties during 2004. At December 31, 2004 there were no wells in progress on the Waddell Ranch properties. There were 2 gross (.88 net) wells drilled and completed on the Waddell Ranch properties during 2003. At December 31, 2003 there were no wells in progress on the Waddell Ranch properties.
     BROG has advised the Trustee that the total amount of capital expenditures for 2005 with regard to the Waddell Ranch properties totaled $14.7 million. Capital expenditures include the cost of remedial and maintenance activities. This amount spent is approximately $.4 million more than the budgeted amount projected by BROG for 2005. BROG has advised the Trustee that the capital expenditures budget for 2006 totals approximately $30.3 million, of which approximately $14.3 million (gross) is attributable to the 2006 drilling program, and $15.0 million (gross) to workovers and recompletions. Accordingly, there is a 106% increase in capital expenditures for 2006 as compared with the 2005 capital expenditures. The major reason for the variance is the increase in the number of planned capital drill wells and rising costs of goods and services. There will be 18 new drill wells in 2006 as compared to 6 in 2005.
     Texas Royalty Properties. The Texas Royalty properties consist of royalty interests in mature producing oil fields, such as Yates, Wasson, Sand Hills, East Texas, Kelly-Snyder, Panhandle Regular, N. Cowden, Todd, Keystone, Kermit, McElroy, Howard-Glasscock, Seminole and others.

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The Texas Royalty properties contain approximately 303,000 gross (approximately 51,000 net) producing acres. Detailed information concerning the number of wells on royalty properties is not generally available to the owners of royalty interests. Consequently, an accurate count of the number of wells located on the Texas Royalty properties cannot readily be obtained.
     In February 1997, BROG sold its interests in the Texas Royalty properties that are subject to the Net Overriding Royalty Conveyance to the Trust dated effective November 1, 1980 (“Texas Royalty Conveyance”) to Riverhill Energy Corporation (“Riverhill Energy”), which was then a wholly-owned subsidiary of Riverhill Capital Corporation (“Riverhill Capital”) and an affiliate of Coastal Management Corporation (“CMC”). At the time of such sale, Riverhill Capital was a privately owned Texas corporation with offices in Bryan and Midland, Texas. The Trustee was informed by BROG that, as required by the Texas Royalty Conveyance, Riverhill Energy succeeded to all of the requirements upon and the responsibilities of BROG under the Texas Royalty Conveyance with regard to the Texas Royalty properties. BROG and Riverhill Energy further advised the Trustee that all accounting operations pertaining to the Texas Royalty properties were being performed by CMC under the direction of Riverhill Energy.
     The Trustee has been advised, effective April 1, 1998, Schlumberger Technology Corporation (“STC”) acquired all of the shares of stock at Riverhill Capital. Prior to the acquisition by STC, CMC and Riverhill Energy were wholly-owned subsidiaries of Riverhill Capital. The Trustee has further been advised, in accordance with the STC acquisition of Riverhill Capital, the shareholders of Riverhill Capital acquired ownership of all shares of stock of Riverhill Energy. Effective January 1, 2001 CMC merged into STC. Thus, the ownership in the Texas Royalty properties remained in Riverhill Energy.
     The Trustee has been advised as of May 1, 2000, the accounting operations, pertaining to the Texas Royalty properties, were being transferred from STC to Riverhill Energy. STC currently conducts all field, technical and accounting operations, on behalf of BROG, with regard to the Waddell Ranch properties. STC currently provides summary reporting of monthly results for both the Texas Royalty properties and the Waddell Ranch properties.
     Well Count and Acreage Summary. The following table shows as of December 31, 2005, the gross and net producing wells and acres for the BROG and Riverhill interests. The net wells and acres are determined by multiplying the gross wells or acres by the BROG and Riverhill interests owner’s working interest in the wells or acres. There is very little undeveloped acreage held by the Trust, and all this is held by production.
                                 
    NUMBER OF WELLS     ACRES  
    Gross     Net     Gross     Net  
BROG and Riverhill Interests
    1,291       577       76,922       33,246  
OIL AND GAS PRODUCTION
     The Trust recognizes production during the month in which the related distribution is received. Production of oil and gas attributable to the Royalties and the Underlying Properties and the related average sales prices attributable to the Underlying Properties for the three years ended December 31, 2005, excluding portions attributable to the adjustments discussed below, were as follows:
                                                                         
    Waddell Ranch   Texas Royalty    
    Properties   Properties   Total
    2005   2004   2003   2005   2004   2003   2005   2004   2003
Royalties:
                                                                       
Production
                                                                       
Oil (barrels)
    501,499       471,441       395,226       325,776       307,611       304,176       827,275       779,052       699,402  
Gas (Mcf)
    3,052,103       2,642,599       2,510,904       556,675       602,518       650,017       3,608,778       3,245,117       3,160,921  
Underlying Properties:
                                                                       
Production
                                                                       
Oil (barrels)
    899,197       873,466       858,225       359,387       349,113       342,619       1,258,584       1,222,579       1,200,844  
Gas (Mcf)
    5,517,845       5,291,295       5,509,899       614,871       684,572       734,057       6,132,716       5,975,867       6,243,956  
Average Price
                                                                       
Oil/barrel
  $ 49.35     $ 37.13     $ 28.25     $ 48.97     $ 34.89     $ 27.70     $ 49.20     $ 36.25     $ 27.97  
Gas/Mcf
  $ 6.90     $ 5.47     $ 4.61     $ 8.22     $ 5.79     $ 4.92     $ 7.11     $ 5.53     $ 4.69  

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     Since the oil and gas sales attributable to the Royalties are based on an allocation formula that is dependent on such factors as price and cost (including capital expenditures), production amounts do not necessarily provide a meaningful comparison.
     Waddell Ranch properties lease operating expense for 2005 was $25.1 million (gross) and $9.1 million (net). The lease operating expense increased 13% from 2004 to 2005 primarily because of an increase in electrical costs. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $6.05/bbl. The lifting cost on a barrel of total fluid produced (BTF) basis was $.50/bbl.
PRICING INFORMATION
     Reference is made to the caption entitled “Regulation” for information as to federal regulation of prices of natural gas. The following paragraphs provide information regarding sales of oil and gas from the Waddell Ranch properties. As a royalty owner, Riverhill is not furnished detailed information regarding sales of oil and gas from the Texas Royalty properties.
     Oil. The Trustee has been advised by BROG that for the period August 1, 1993 through February 28, 2006, the oil from the Waddell Ranch properties was and will be sold under a competitive bid to independent third parties.
     Gas. The gas produced from the Waddell Ranch properties is processed through a natural gas processing plant and sold at the tailgate of the plant. Plant products are marketed by Burlington Resources Trading Inc., an indirect subsidiary of BRI. The processor of the gas (Warren Petroleum Company, L.P.) receives 15% of the liquids and residue gas as a fee for gathering, compression, treating and processing the gas.
OIL AND GAS RESERVES
     The following are definitions adopted by the Securities and Exchange Commission (“SEC”) and the Financial Accounting Standards Board which are applicable to terms used within this Item:
     “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.
     “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

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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 herein as “estimated future net cash flows.”
     “Present value of estimated future net revenues” is computed using the estimated future net revenues and a discount factor of 10%.
     The independent petroleum engineers’ reports as to the proved oil and gas reserves attributable to the Royalties conveyed to the Trust were obtained from Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities from January 1, 2003 through December 31, 2005 (in thousands):
                                                 
    Waddell Ranch     Texas Royalty     Total  
    Properties     Properties              
    Oil     Gas     Oil     Gas     Oil     Gas  
    (Bbls)     (Mcf)     (Bbls)     (Mcf)     (Bbls)     (Mcf)  
    4,047       22,940       3,439       5,565       7,486       28,505  
Extensions, discoveries, and other additions
    0       0       0       0       0       0  
Revisions of previous estimates
    (121 )     1,393       241       510       120       1,903  
Production
    (395 )     (2,511 )     (304 )     (650 )     (699 )     (3,161 )
 
                                   
 
                                               
    3,531       21,822       3,376       5,425       6,907       27,247  
Extensions, discoveries, and other additions
    0       0       0       0       0       0  
Revisions of previous estimates
    546       2,692       434       1,091       980       3,783  
Production
    (471 )     (2,643 )     (308 )     (602 )     (779 )     (3,245 )
 
                                   
 
                                               
    3,606       21,871       3,502       5,914       7,108       27,785  
Extensions, discoveries, and other additions
    84       415       0       0       84       415  
Revisions of previous estimates
    126       1,695       359       246       485       1,941  
Production
    (501 )     (3,052 )     (326 )     (557 )     (827 )     (3,609 )
 
                                   
 
                                               
    3,315       20,929       3,535       5,603       6,850       26,532  
     Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2005, 2004 and 2003 were as follows (in thousands):
                 
    Crude Oil     Natural Gas  
    (Bbls)     (Mcf)  
    6,764       25,877  
    6,988       27,545  
    6,470       26,475  
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 computed by applying year-end prices of oil and gas relating to the enterprise’s proved reserves to the year-end quantities of those reserves. 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 cash flows relating to proved oil and gas reserves.

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Estimates of proved oil and gas reserves are by their very nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables.
The 2005, 2004 and 2003 change in the standardized measure of discounted future net cash revenues related to future royalty income from proved reserves attributable to the Royalties discounted at 10% is as follows (in thousands):
                                                                         
            Waddell Ranch                     Texas Royalty                     Total        
            Properties                     Properties                          
    2005     2004     2003     2005     2004     2003     2005     2004     2003  
January 1
  $ 156,014     $ 117,755     $ 117,234     $ 81,179     $ 57,796     $ 55,972     $ 237,193     $ 175,551     $ 173,206  
Extensions, discoveries, and other additions
    3,743       0       0       0       0       0       3,743       0       0  
 
                                                                       
Accretion of discount
    15,601       11,776       11,723       8,118       5,780       5,597       23,719       17,556       17,320  
Revisions of previous estimates and other
    56,830       57,820       10,318       34,833       31,283       7,303       91,663       89,103       17,621  
 
                                                                       
Royalty income
    (43,491 )     (31,337 )     (21,520 )     (19,476 )     (13,680 )     (11,076 )     (62,967 )     (45,017 )     (32,596 )
     
December 31
  $ 188,697     $ 156,014     $ 117,755     $ 104,654     $ 81,179     $ 57,796     $ 293,351     $ 237,193     $ 175,551  
 
                                                     
Oil and gas prices of $54.89 and $54.02 per barrel and $6.38 and $7.06 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2005. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties are primarily due to increase in oil and gas prices from 2004 to 2005.
Oil and gas prices of $37.90 and $39.07 per barrel and $6.22 and $6.61 per Mcf were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2004. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties were mostly due to increase in oil and gas prices from 2003 to 2004.
Oil and gas prices of $30.70 and $29.91 per barrel and $4.76 and $4.71 per Mcf, respectively, were used to determine the estimated future net revenues from the Waddell Ranch properties and the Texas Royalty properties, respectively, at December 31, 2003. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties were primarily due to increases in oil and gas prices from 2002 to 2003.
The following presents estimated future net revenue and the present value of estimated future net revenue attributable to the Royalties, for each of the years ended December 31, 2005, 2004 and 2003 (in thousands except amounts per Unit):
                                                 
    2005     2004     2003  
    Estimated     Present     Estimated     Present     Estimated     Present  
    Future Net     Value at     Future Net     Value at     Future Net     Value at  
    Revenue     10%     Revenue     10%     Revenue     10%  
Total Proved
                                               
Waddell Ranch properties
  $ 298,417     $ 188,697     $ 257,563     $ 156,014     $ 200,297     $ 117,755  
Texas Royalty properties
  $ 219,657     $ 104,654     $ 167,402     $ 81,179       120,410       57,796  
 
                                   
Total
  $ 518,074     $ 293,351     $ 424,965     $ 237,193     $ 320,707     $ 175,551  
Reserve quantities and revenues shown in the preceding tables for the Royalties were estimated from projections of reserves and revenue attributable to the combined BROG, River Hill Energy and Trust interests in the Waddell Ranch properties and Texas Royalty properties. Reserve quantities attributable to the Royalties were estimated by allocating to the Royalties a portion of the total estimated net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities

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attributable to the Royalties 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 Royalties. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur.
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 original estimate. Moreover, the present values shown above should not be considered as 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 include many additional factors.
Detailed information concerning the number of wells on royalty properties is not generally available to the owner of royalty interests. Consequently, the Registrant does not have information that would be disclosed by a company with oil and gas operations, such as an accurate account of the number of wells located on the above royalty properties, the number of exploratory or development wells drilled on the above royalty properties during the periods presented by this report, or the number of wells in process or other present activities on the above royalty properties, and the Registrant cannot readily obtain such information.
REGULATION
Many aspects of the production, pricing, transportation 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 can be produced, potentially raise prices, and to limit the number of wells or the locations which can be drilled.
Federal Natural Gas Regulation
The Federal Energy Regulatory Commission (the “FERC”) is primarily responsible for federal regulation of natural gas. The interstate transportation and sale for resale of natural gas is subject to federal governmental regulation, including regulation of transportation and storage tariffs and various other matters, by FERC. On August 8, 2005, Congress enacted the Energy Policy Act of 2005. The Energy Policy Act, among other things, amended the Natural Gas Act to prohibit market manipulation by any entity, to direct FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce, and to significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, or FERC rules, regulations or orders thereunder. Wellhead sales of domestic natural gas are not subject to regulation. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions.
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 the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, the 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 the FERC’s

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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. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions.
New proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, the 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 recently pursued by the FERC and Congress will continue.
Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. Crude oil prices are affected by a variety of factors. Since domestic crude price controls were lifted in 1981, the principal factors influencing the prices received by producers of domestic crude oil have been the pricing and production of the members of the Organization of Petroleum Export Countries (OPEC).
State Regulation
The various states regulate the production and sale of oil and natural gas, including imposing requirements for obtaining drilling permits, the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and gas resources. The rates of production may be regulated and the maximum daily production allowables from both oil and gas wells may be established on a market demand or conservation basis, or both.
Other Regulation
The petroleum 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. The Trustee does not believe that compliance with these laws by the operating parties will have any material adverse effect on Unit holders.

Item 3. Legal Proceedings
There are no material pending legal proceedings to which the Trust is a party or of which any of its property is the subject.

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, 2005.

PART II

Item 5. Market for Units of the Trust, Related Security Holder Matters and Trust Purchases of Units
The information under “Units of Beneficial Interest” at page 1 of the Trust’s Annual Report to security holders for the year ended December 31, 2005, is herein incorporated by reference.
The Trust has no equity compensation plans and has not repurchased any units during the period covered by this report.

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Item 6. Selected Financial Data
                                         
    For the Year Ended December 31,  
    2005     2004     2003     2002     2001  
Royalty income
  $ 62,967,150     $ 45,016,670     $ 32,596,078     $ 23,830,604     $ 39,816,141  
Distributable income
  $ 62,267,669       44,546,743       32,113,125       23,415,406       39,473,395  
Distributable income per Unit
    1.335964       .955758       0.688993       0.502382       0.846908  
Distributions per Unit
    1.335964       .955758       0.688993       0.502382       0.846908  
Total assets, December 31
  $ 8,874,678     $ 7,224,412     $ 4,865,569     $ 4,543,780     $ 4,213,606  

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
     The “Trustee’s Discussion and Analysis for the Three Year Period Ended December 31, 2005 and “Results of the 4th Quarters of 2005 and 2004” at pages 7 et seq. of the Trust’s Annual Report to security holders for the year ended December 31, 2005 is herein incorporated by reference.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk
     The Trust is a passive entity and other than the Trust’s ability to periodically borrow money as necessary to pay expenses, liabilities and obligations of the Trust that cannot be paid out of cash held by the Trust, the Trust is prohibited from engaging in borrowing transactions. 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 invests in no derivative financial instruments and has no foreign operations or long-term debt instruments.

Item 8. Financial Statements and Supplementary Data
     The Financial Statements of the Trust and the notes thereto at page 12 et seq. of the Trust’s Annual Report to security holders for the year ended December 31, 2005, are herein incorporated by reference.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
     There have been no changes in accountants and no disagreements with accountants on any matter of accounting principles or practices or financial statement disclosures during the twenty-four months ended December 31, 2005.

Item 9A. Controls and Procedures.
Disclosure Controls and Procedures
     As of the end of the period covered by this report, the Trustee carried out an evaluation of the effectiveness of the design and operation of the Trust’s disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 promulgated under the Securities and Exchange Act of 1934, as amended. Based

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upon that evaluation, the Trustee concluded that the Trust’s disclosure controls and procedures are effective in timely alerting the Trustee to material information relating to the Trust required to be included in the Trust’s periodic filings with the Securities and Exchange Commission. In its evaluation of disclosure controls and procedures, the trustee has relied, to the extent considered reasonable, on information provided by Burlington Resources Oil & Gas Company, the owner of the Waddell Ranch properties, and Riverhill Energy Corporation, the owner of the Texas Royalty properties.
Changes in Internal Control over Financial Reporting
     There has not been any change in the Trust’s internal control over financial reporting during the fourth quarter of 2005 that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.
Trustee’s Report on Internal Control Over Financial Reporting
     The Trustee is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) promulgated under the Securities and Exchange Act of 1934, as amended. The Trustee conducted an evaluation of the effectiveness of the Trust’s internal control over financial reporting – modified cash basis (“internal control over financial reporting”) based on the criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the Trustee’s evaluation under the framework in Internal Control-Integrated Framwork, the Trustee concluded that the Trust’s internal control over financial reporting was effective as of December 31, 2005. The Trustee’s assessment of the effectiveness of the Trust’s internal control over financial reporting as of December 31, 2005 has been audited by Deloitte & Touche LLP, an independent registered public accounting firm, as stated in their report which is included herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Unit Holders of Permian Basin Royalty Trust and
Bank of America, N.A., Trustee
We have audited the Trustee’s assessment, included in the accompanying Trustee’s report on internal control over financial reporting that Permian Basin Royalty Trust (the “Trust”) maintained effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Trustee is responsible for maintaining effective internal control over financial reporting — modified cash basis (“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 management’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 opinions.
The Trust’s internal control over financial reporting is a process designed by, or under the supervision of, the Trustee, or persons performing similar functions, and effected by the Trustee to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with the modified cash basis of accounting, which is a comprehensive basis of accounting other than accounting principles generally accepted in the United States of America and is described in Note 3 to the Trust’s financial statements. The 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 the modified cash basis of accounting discussed above, and that receipts and expenditures of the Trust are being made only in accordance with authorizations of the Trustee; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Trust’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis.

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Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, 2005, is fairly stated, in all material respects, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Trust maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
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 of Permian Basin Royalty Trust (the “Trust”) as of December 31, 2005 and 2004, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 2005, which financial statements have been prepared on the modified cash basis of accounting as described in Note 3 to such financial statements, and our report dated March 14, 2006 expressed an unqualified opinion on those financial statements.
DELOITTE & TOUCHE LLP
Dallas, Texas
March 14, 2006

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Item 9B. Other Information.
None.

PART III

Item 10. Directors and Executive Officers of the Registrant
DIRECTORS AND OFFICERS
     The Trust has no directors or executive officers. 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.
AUDIT COMMITTEE AND NOMINATING COMMITTEE
     Because the Trust has no directors, it does not have an audit committee, an audit committee financial expert or a nominating committee.

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SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
     Section 16(a) of the Securities Exchange At of 1934 requires the Trust’s directors, officers or beneficial owners of more than ten percent of a registered class of the Trust’s equity securities to file reports of ownership and changes in ownership with the SEC and to furnish the Trust with copies of all such reports.
     The Trust has no directors or officers and based solely on its review of the reports received by it, the Trust believes that during the fiscal year of 2005, no person who was a beneficial owner of more than ten percent the Trust’s Units failed to file on a timely basis any report required by Section 16(a), with the exception of filings related to sales of units of the Trust on two occasions that were inadvertently untimely filed by BROG.
CODE OF ETHICS
     Because the Trust has no employees, it does not have a code of ethics. Employees of the Trustee, Bank of America, N.A., must comply with the bank’s code of ethics, a copy of which will be provided to Unit holders, without charge, upon request made to Bank of America, N.A., Trustee, P.O. Box 830650, Dallas, Texas 75202, Attention: Ron Hooper.

Item 11. Executive Compensation
     During the years ended December 31, 2005, 2004 and 2003, the Trustee received total remuneration as follows:
                 
       
Name of Individual or Number   Cash    
of Persons in Group   Compensation   Year
Bank of America, N.A
  $ 78,294 (1)     2005  
 
  $ 46,693 (1)     2004  
 
  $ 41,608 (1)     2003  
 
(1)   Under the Trust Indenture, the Trustee is entitled to an administrative fee for its administrative services, preparation of quarterly and annual statements with attention to tax and legal matters of: (i) 1/20 of 1% of the first $100 million and (ii) Trustee’s standard hourly rate in excess of 300 hours annually. The administrative fee is subject to reduction by a credit for funds provision.

Item 12. Security Ownership of Certain Beneficial Owners and Management
     (a) Security Ownership of Certain Beneficial Owners. The following table sets forth as of March 1, 2006, information with respect to each person known to own beneficially more than 5% of the outstanding Units of the Trust:

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    Amount and Nature of        
Name and Address   Beneficial Ownership     Percent of Class  
Burlington Resources Oil & Gas Company LP(1)
717 Texas Avenue, Suite 2100
Houston, Texas 77002
  9,620,741 Units     20.6 %
 
(1)   Based on information provided to the Trustee by BROG.
     (b) Security Ownership of Management. The Trustee does not beneficially own any securities of the Trust. In various fiduciary capacities, Bank of America, N.A. owned as of March 1, 2006, an aggregate of 146,293 Units with no right to vote all of these Units, shared right to vote none of these Units and sole right to vote none of these Units. Bank of America, N.A., disclaims any beneficial interests in these Units. The number of Units reflected in this paragraph includes Units held by all branches of Bank of America, N.A.
     (c) Change In Control. The Trustee knows of no arrangements which may subsequently result in a change in control of the Trust.

Item 13. Certain Relationships and Related Transactions
     The Trust has no directors or executive officers. See Item 11 for the remuneration received by the Trustee during the years ended December 31, 2005, 2004 and 2003 and Item 12(b) for information concerning Units owned by Bank of America, N.A. in various fiduciary capacities.

Item 14. Principal Accounting Fees and Services. Fees for services performed by Deloitte & Touche LLP for the years ended December 31, 2005 and 2004 are:
                 
    2005   2004
Audit Fees
  $ 132,850     $ 65,000  
Audit-related fees
           
Tax fees
           
All other fees
           
     
Total
  $ 132,850     $ 65,000  
     As referenced in Item 10 above, the Trust has no audit committee, and as a result, has no audit committee pre-approval policy with respect to fees paid to Deloitte & Touche LLP.

PART IV

Item 15. Exhibits, Financial Statement Schedules
     The following documents are filed as a part of this Report:
1. Financial Statements
     Included in Part II of this Report by reference to the Annual Report of the Trust for the year ended December 31, 2005:
Report of Independent Registered Public Accounting Firm
Statements of Assets, Liabilities and Trust Corpus at December 31, 2005 and 2004

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Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2005
Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2005
Notes to Financial Statements
2. 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.
3. Exhibits
         
Exhibit        
Number       Exhibit
(4)(a)    
Permian Basin Royalty Trust Indenture dated November 3, 1980, between Southland Royalty Company and The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, heretofore filed as Exhibit (4)(a) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(b)    
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) from Southland Royalty Company to The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit (4)(b) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(c)    
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust — Waddell Ranch) from Southland Royalty Company to The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit (4)(c) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(10)(a)    
Underwriting Agreement dated December 15, 2005 among the Permian Basin Royalty Trust, Burlington Resources, Inc., Burlington Resources Oil & Gas L.P. and Lehman Brothers Inc. and Wachovia Capital Markets, LLC as representatives of the several underwriters, heretofore filed as Exhibit 10.1 to the Trust’s current report filed on Form 8-K to the Securities and Exchange Commission filed on December 19, 2005, is incorporated herein by reference.*
       
 
(b)    
Underwriting Agreement dated August 2, 2005 among the Permian Basin Royalty Trust, Burlington Resources, Inc., Burlington Resources Oil & Gas L.P. and Goldman Sachs & Co. and Lehman Brothers Inc. as representatives of the several underwriters, heretofore filed as Exhibit 10.1 to the Trust’s current report filed on Form 8-K to the Securities and Exchange Commission filed on August 8, 2005, is incorporated herein by reference.*
       
 
(c)    
Registration Rights Agreement dated as of July 21, 2004 by and between Burlington Resources, Inc. and Bank of America, N.A., as trustee of

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Exhibit        
Number       Exhibit
       
Permian Basin Royalty Trust, heretofore filed as Exhibit 10.1 to the Trust’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarterly period ended June 30, 2004 is incorporated herein by reference.*
       
 
(13)    
Registrant’s Annual Report to security holders for fiscal year ended December 31, 2005.**
       
 
(23.1)    
Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
       
 
(23.2)    
Consent of Deloitte & Touche LLP
       
 
(31.1)    
Certification required by Rule 13a-14(a)/15d-14(a).**
       
 
(32.1)    
Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.**
 
*   A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon written request to the Trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.
 
**   Filed 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.
         
    PERMIAN BASIN ROYALTY TRUST
 
       
    By: BANK OF AMERICA, N.A., Trustee
 
       
 
      By:  /s/Ron E. Hooper
 
       
 
              Ron E. Hooper
 
              Senior Vice President
       
(The Trust has no directors or executive officers.)

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INDEX TO EXHIBITS
         
EXHIBIT        
NUMBER       EXHIBIT
(4)(a)    
Permian Basin Royalty Trust Indenture dated November 3, 1980, between Southland Royalty Company and The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, heretofore filed as Exhibit (4)(a) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(b)    
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust) from Southland Royalty Company to The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit (4)(b) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(c)    
Net Overriding Royalty Conveyance (Permian Basin Royalty Trust — Waddell Ranch) from Southland Royalty Company to The First National Bank of Fort Worth (now Bank of America, N.A.), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit (4)(c) to the Trust’s Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.*
       
 
(10)(a)    
Underwriting Agreement dated December 15, 2005 among the Permian Basin Royalty Trust, Burlington Resources, Inc., Burlington Resources Oil & Gas L.P. and Lehman Brothers Inc. and Wachovia Capital Markets, LLC as representatives of the several underwriters, heretofore filed as Exhibit 10.1 to the Trust’s current report filed on Form 8-K to the Securities and Exchange Commission filed on December 19, 2005, is incorporated herein by reference.*
       
 
(b)    
Underwriting Agreement dated August 2, 2005 among the Permian Basin Royalty Trust, Burlington Resources, Inc., Burlington Resources Oil & Gas L.P. and Goldman Sachs & Co. and Lehman Brothers Inc. as representatives of the several underwriters, heretofore filed as Exhibit 10.1 to the Trust’s current report filed on Form 8-K to the Securities and Exchange Commission filed on August 8, 2005, is incorporated herein by reference.*

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EXHIBIT        
NUMBER       EXHIBIT
(c)    
Registration Rights Agreement dated as of July 21, 2004 by and between Burlington Resources, Inc. and Bank of America, N.A., as trustee of Permian Basin Royalty Trust, heretofore filed as Exhibit 10.1 to the Trust’s Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarterly period ended June 30, 2004 is incorporated herein by reference.*
       
 
(13)    
Registrant’s Annual Report to security holders for fiscal year ended December 31, 2005.**
       
 
(23.1)    
Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
       
 
(23.2)    
Consent of Deloitte & Touche LLP
       
 
(31.1)    
Certification required by Rule 13a-14(a)/15d-14(a).**
       
 
(32.1)    
Certification required by Rule 13a-14(b)/15d-14(b) and Section 906 of the Sarbanes-Oxley Act of 2002.**
 
*   A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon written request to the Trustee, Bank of America, N.A., P.O. Box 830650, Dallas, Texas 75283-0650.
 
**   Filed herewith.

27


Dates Referenced Herein   and   Documents Incorporated By Reference

This 10-K Filing   Date   Other Filings
8/1/93
4/1/98
5/1/00
1/1/01
1/1/03
12/31/0310-K
6/30/0410-Q
7/21/04
12/31/0410-K, 10-K/A
8/2/054, 8-K
8/8/058-K
12/12/05
12/15/058-K
12/19/05424B5, 8-K
For The Period Ended12/31/05
2/28/06
3/1/06
3/14/06
Filed On / Filed As Of3/15/06
 
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