PERMIAN BASIN ROYALTY TRUST - Annual Report: 2003 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

(Mark One)

OR

Commission file number 1-8033

PERMIAN BASIN ROYALTY TRUST

(Exact Name of Registrant as Specified in the Permian Basin Royalty Trust Indenture)

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:

SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None

     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 [ X ] No [  ]

     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. [X]

     Indicate by check mark whether the registrant is an accelerated filed (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes [X] No [  ]

     The aggregate market value of the registrant’s units of beneficial interest outstanding (based on the closing sale price on the New York Stock Exchange) held by non-affiliates of the registrant as of the last business day of the registrant’s most recently completed second fiscal quarter was approximately $103,268,565.

     At March 1, 2004, 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, 2002” at pages 7 through 10; “Results of the 4th Quarters of 2002 and 2001” at page 9 ; and “Statements of Assets, Liabilities and Trust Corpus,” “Statements of Distributable Income,” “Statements of Changes in Trust Corpus,” “Notes to Financial Statements” and “Independent Auditors’ Report” at page 11 et seq., in registrant’s Annual Report to security holders for fiscal year ended December 31, 2002 are incorporated herein by reference for Item 5, Item 7 and Item 8 of Part II of this Report.

Table of Contents

TABLE OF CONTENTS

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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. 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.

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 these transactions, El Paso Natural Gas Company (“El Paso”) also became an indirect subsidiary of BRI. In March 1992, El Paso completed an initial public offering of 5,750,000 newly issued shares of El Paso common stock, thereby decreasing BRI’s ownership of El Paso to approximately eighty-five percent (85%). On June 30, 1992, BRI distributed all of the shares of El Paso common stock

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owned by BRI to BRI’s stockholders of record as of June 15, 1992. See “Pricing Information” under “ITEM 2. Properties” herein.

     Effective January 1, 1996, Southland Royalty, a wholly-owned subsidiary of Meridian Oil Inc. (“MOI”) was merged with and into MOI, by which action 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 has assumed all of its rights, powers and privileges, and all of its liabilities and obligations. In 1996, MOI changed its name to Burlington Resources Oil & Gas Company (“BROG”).

     The term “net proceeds” as used in the above described conveyance means the excess of “gross proceeds” received by BROG (the “Company”) 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 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.

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Website/SEC Filings

     Our Internet address is http://www.pbt-permianbasintrust.com. You can review 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 2. Properties

     The net overriding royalties conveyed to the Trust (the “Royalties”) include: (1) a 75% net overriding royalty carved out of BROG’s (as successor to Southland Royalty) 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 BROG’s (as successor to Southland Royalty) 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 furnished to the Trustee by BROG.

PRODUCING ACREAGE, WELLS AND DRILLING

     Waddell Ranch Properties. The Waddell Ranch properties consist of 78,175 gross (34,205 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, 2003, the Waddell Ranch properties contained 716 gross (316 net) productive oil wells, 186 gross (88 net) productive gas wells and 323 gross (141 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 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. There were 4 gross (1.75 net) wells drilled and completed on the Waddell Ranch properties during 2002. At December 31, 2002 there were no wells in progress on the Waddell Ranch properties. During 2001 there were 11 gross (4.87 net) wells drilled and completed on the Waddell Ranch properties. At December 31, 2001 there were 8 gross (3.75 net) wells in progress on the Waddell Ranch properties.

     BROG has advised the Trustee that the total amount of capital expenditures for 2003 with regard to the Waddell Ranch properties totalled $11.8 million. Capital expenditures include the cost of remedial and maintenance activities. This amount spent is approximately $1.8 million more than the budgeted amount projected by BROG for 2003. BROG has advised the Trustee that the capital expenditures budget for 2004 totals approximately 13.2 million, of which approximately $2.0 million is attributable to the 2004 drilling program, and $11.1 million gross to workovers and recompletions. Accordingly, there is a 12% increase in capital expenditures for 2004 as compared with the 2003 capital expenditures.

     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,

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McElroy, Howard-Glasscock, Seminole and others. 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. BROG indicated to the Trustee that BROG will work together with CMC and Riverhill Energy in an effort to assure that various administrative functions and reporting requirements assumed by Riverhill Energy are met. The Trustee has been advised that independent auditors representing Riverhill Energy and CMC are PriceWaterhouseCoopers.

     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, are 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, 2003, the gross and net producing wells and acres for the Company Interests. The net wells and acres are determined by multiplying the gross wells or acres by the Company 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.

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, 2003, excluding portions attributable to the adjustments discussed below, were as follows:

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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 2003 was $22,417,000 (gross) and $8,556,913 (net). The lease operating expense increased 11% from 2002 to 2003 primarily because of 2002 deregulation of electricity markets which caused a decline of 2002 invoices. Waddell Ranch lifting cost on a barrel of oil equivalent (BOE) basis was $5.41/bbl. The lifting cost on a barrel of total fluid produced (BTF) basis was $.44/bbl.

PRICING INFORMATION

     Reference is made to “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, BROG 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 June 30, 2004, 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 Hydrocarbons 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 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%.

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     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, 2001 through December 31, 2003 (in thousands):

     Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2003, 2002 and 2001 were as follows (in thousands):

     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.

     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.

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     The 2003, 2002 and 2001 change in the standardized measure of discounted future net cash revenues related to future royalty income from proved reserves attributable to te Royalties discounted at 10% is as follows (in thousands):

     Oil and gas prices of $30.70 and $29.91 per barrel and $4.76 and $4.71 per Mcf 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 are mostly due to increase in oil and gas prices from 2002 to 2003.

     Oil and gas prices of $31.88 and $28.95 per barrel and $3.80 and $3.79 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, 2002. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties are due to increase in oil and gas prices from 2001 to 2002.

     Oil and gas prices of $17.05 and $17.62 per barrel and $2.15 and $1.93 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, 2001. The upward revisions of both reserves and discounted future net cash flows for the Waddell Ranch properties and the Texas Royalty properties are due to increases in oil and gas prices from 2000 to 2001.

     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, 2003, 2002 and 2001 (in thousands except amounts per Unit):

     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 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.

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     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.

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. 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 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).

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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, 2003.

PART II

Item 5. Market for Units of the Trust and Related Security Holder Matters

     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, 2003, 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.

Item 6. Selected Financial Data

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, 2003” and “Results of the 4^th Quarters of 2003 and 2002” at pages 6 through 8 of the Trust’s Annual Report to security holders for the year ended December 31, 2003 is herein incorporated by reference.

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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 9 et seq. of the Trust’s Annual Report to security holders for the year ended December 31, 2003, 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, 2003.

Item 9A. 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 Exchange Act Rule 13a-15 and 15d-15. Based 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 and River Hill Energy Corporation. There has not been any change in the Trust’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust’s internal control over financial reporting.

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.

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.

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     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 2003, 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).

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, 2003, 2002 and 2001, the Trustee received total remuneration as follows:

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, 2004, information with respect to each person known to own beneficially more than 5% of the outstanding Units of the Trust:

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     (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, 2004, an aggregate of 143,065 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, 2002, 2001 and 2000 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, 2003 and 2002 are:

     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.

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PART IV

Item 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K

     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, 2003:

Independent Auditors’ Report

Statements of Assets, Liabilities and Trust Corpus at December 31, 2003 and 2002

Statements of Distributable Income for Each of the Three Years in the Period Ended December 31, 2003

Statements of Changes in Trust Corpus for Each of the Three Years in the Period Ended December 31, 2003

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

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REPORTS ON FORM 8-K

     During the last quarter of the Trust’s fiscal year ended December 31, 2003, there were no reports on Form 8-K filed by the Trust. Forms 8-K were furnished by the Trust on November 20, 2003 and December 12, 2003, pursuant to item 12 of Form 8-K announcing the Trust’s monthly distributions.

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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.

Date: March 12, 2004

(The Trust has no directors or executive officers.)

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INDEX TO EXHIBITS

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