10-K/A 1 d04301a1e10vkza.txt AMENDMENT TO FORM 10-K -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 --------------------- FORM 10-K/A (Mark One) [X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-8032 SAN JUAN BASIN ROYALTY TRUST (Exact name of registrant as specified in the Amended and Restated San Juan Basin Royalty Trust Indenture) TEXAS 75-6279898 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification No.) TEXASBANK, TRUST DEPARTMENT 2525 RIDGMAR BOULEVARD, SUITE 100 FORT WORTH, TEXAS 76116 (Address of principal executive offices) (Zip Code)
(866) 809-4553 (Registrant's telephone number, including area code) SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED ------------------- ----------------------------------------- Units of Beneficial Interest New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE (Title of Class) Indicate by check mark 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. Yes [X] No [ ] Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Act). Yes [X] No [ ] State the aggregate market value of the Units of Beneficial Interest held by non-affiliates of the Registrant as of June 28, 2002: $515,959,372. At March 25, 2003, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding. DOCUMENTS INCORPORATED BY REFERENCE "Units of Beneficial Interest" at page 1; "Description of the Properties" at pages 5 and 6; "Trustee's Discussion and Analysis" at pages 7, 8 and 9; "Results of the 4th Quarters of 2002 and 2001" at page 10; and "Statements of Assets, Liabilities and Trust Corpus," "Statements of Distributable Income," "Statements of Change in Trust Corpus," "Notes to Financial Statements," and "Independent Auditor's Report" at page 11 et seq., in registrant's Annual Report to Unit Holders for the year ended December 31, 2002 are incorporated herein by reference for Item 2 (Properties) and Item 3 (Legal Proceedings) of Part I of this Report, and Item 5 (Market for Units of the Trust and Related Security Holder Matters), Item 7 (Management's Discussion and Analysis of Financial Condition and Results of Operation) and Item 8 (Financial Statements and Supplementary Data) of Part II of this Report. -------------------------------------------------------------------------------- -------------------------------------------------------------------------------- EXPLANATORY NOTE This Amendment No. 1 to the San Juan Basin Royalty Trust's Annual Report on Form 10-K for its fiscal year ended December 31, 2002 is being filed to amend the estimated future net revenues and present value of estimated future net revenues table on page 9 of the Annual Report solely to revise the 2002 per Unit information. This Amendment No. 1 does not reflect events occurring after the filing of the original Form 10-K and does not modify or update the disclosures in the original Form 10-K in any way other than as described in this Explanatory Note. PART I Certain information included in this Annual Report on Form 10-K/A contains, and other materials filed or to be filed by the San Juan Basin Royalty Trust (the "Trust") with the Securities and Exchange Commission (as well as information included in oral statements or other written statements made or to be made by the Trust) may contain or include, forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, and Section 27A of the Securities Act of 1933. Such forward-looking statements may be or may concern, among other things, capital expenditures, drilling activity, development activities, production efforts and volumes, hydrocarbon prices and the results thereof, and regulatory matters. Such forward-looking statements generally are accompanied by words such as "may," "will," "estimate," "expect," "predict," "anticipate," "goal," "should," "assume," "believe," "plan," "intend," or other words that convey the uncertainty of future events or outcomes. Such statements reflect Burlington Resources Oil & Gas Company LP's ("BROG"), the working interest owner's, current view with respect to future events; are based on an assessment of, and are subject to, a variety of factors deemed relevant by TexasBank, the Trustee of the Trust, and BROG and involve risks and uncertainties. Should one or more of these risks or uncertainties occur, actual results may vary materially and adversely from those anticipated. ITEM 1. BUSINESS The Trust is an express trust created under the laws of the state of Texas by the San Juan Basin Royalty Trust Indenture (the "Original Indenture") entered into on November 3, 1980, between Southland Royalty Company ("Southland Royalty") and the Fort Worth National Bank. Effective as of September 30, 2002, the Original Indenture was amended and restated (the Original Indenture, as amended and restated, the "Trust Indenture"). The Trustee of the Trust is TexasBank. The principal office of the Trust is located at 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116, Attention: Trust Department (telephone number (866) 809-4553). The Trust maintains a website at www.sjbrt.com. The Trust makes available (free of charge) its annual, quarterly and current reports (and any amendments thereto) filed with the Securities and Exchange Commission (the "SEC") on its website as soon as reasonably practicable after electronically filing such material with, or furnishing it to, the SEC. On October 23, 1980, the stockholders of Southland Royalty approved and authorized that company's conveyance of a net overriding royalty interest (equivalent to a net profits interest) to the Trust for the benefit of the stockholders of Southland Royalty of record at the close of business on the date of the conveyance consisting of a 75% net overriding royalty interest carved out of that company's oil and gas leasehold and royalty interests (the "Underlying Interests") in properties located in the San Juan Basin of northwestern New Mexico (the "Underlying Properties"). The conveyance of this net overriding royalty interest (the "Royalty") was made on November 3, 1980, effective as to production from and after November 1, 1980 at 7:00 A.M. The Royalty was carved out of and now burdens those properties and interests as more particularly described under "Item 2. Properties" herein. The Royalty constitutes the principal asset of the Trust and the beneficial interests in the Royalty are divided into that number of Units of Beneficial Interest (the "Units") of the Trust equal to the number of shares of the common stock of Southland Royalty outstanding as of the close of business on November 3, 1980. Each stockholder of Southland Royalty of record at the close of business on November 3, 1980 received 2 one Unit for each share of the common stock of Southland Royalty then held. Holders of Units are referred to herein as "Unit Holders." The function of the Trustee is to collect the income attributable to the Royalty, 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. 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, Meridian Oil, Inc. ("MOI") also became an indirect subsidiary of BRI. Effective January 1, 1996, Southland Royalty, a wholly-owned subsidiary of MOI, was merged with and into MOI, by which action the separate corporate existence of Southland Royalty ceased to exist and MOI survived and succeeded to the ownership of all of the assets, rights, powers and privileges and assumed all of the liabilities and obligations of Southland Royalty. Subsequent to the merger, MOI changed its name to BROG. The term "net proceeds," as used in the November 3, 1980 conveyance, means the excess of "gross proceeds" received by BROG during a particular period over "production costs" for such period. "Gross proceeds" means the amount received by BROG (or any subsequent owner of the Underlying Interests) from the sale of the production attributable to the Underlying Interests subject to certain adjustments. "Production costs" generally means costs incurred on an accrual basis by BROG in operating its properties and interests out of which the Royalty was carved, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes and operating charges. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to these properties and interests or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such amount, plus interest, at a rate specified in the conveyance. Certain of the Underlying Interests are operated by BROG with the obligation to conduct its operations in accordance with reasonable and prudent business judgment and good oil and gas field practices. As operator, BROG has the right to abandon any well when, in its opinion, such well ceases to produce or is not capable of producing oil and gas in paying quantities. BROG also is responsible, subject to the terms of a settlement agreement with the Trust, for marketing the production from such properties, either under existing sales contracts or under future arrangements at the best prices and on the best terms it shall deem reasonably obtainable in the circumstances. BROG also has the obligation to maintain books and records sufficient to determine the amounts payable to the Trustee. BROG, however, can sell its interest 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 Royalty are paid by BROG to the Trustee in the third month and distribution by the Trustee to the Unit Holders is made in the fourth month. 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) the net proceeds attributable to the Royalty paid to the Trustee, plus any decrease in cash reserves previously established for contingent liabilities and any other cash receipts of the Trust, over (ii) the expenses and payments of liabilities of the Trust, plus any net increase in cash reserves for contingent liabilities. Cash being held by the Trustee as a reserve for liabilities or contingencies (which reserves may be established by the Trustee in its discretion) or pending distribution is placed, in the Trustee's discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any agency thereof, repurchase 3 agreements secured by obligations issued by the United States or any agency thereof, certificates of deposit of banks having capital, surplus and undivided profits in excess of $50,000,000, or money market funds that have been rated AAAmg or AAAm by Standard & Poor's and AA by Moody's, subject, in each case, to certain other qualifying conditions. The Underlying Properties are primarily gas producing properties. Normally there is a greater demand for gas in the winter months than during the rest of the year. Otherwise, the income to the Trust attributable to the Royalty is not subject to seasonal factors nor in any manner related to or dependent upon patents, licenses, franchises or concessions. The Trust conducts no research activities. Based on its 1999 year-end review, BROG determined that it had undercharged the Trust for both capital expenditures and lease operating charges related to properties burdened by the Trust but not operated by BROG. In April and May of 2000, BROG passed through to the Trust additional charges of $652,303 in capital expenditures and $1,689,509 in lease operating charges related to the undercharged non-operated properties. The Trust's consultants have reviewed BROG's cost reporting data and confirmed that these additional charges were appropriate. ITEM 2. PROPERTIES The Royalty conveyed to the Trust was carved out of Southland Royalty's (now BROG's) working interests and royalty interests in certain properties situated in the San Juan Basin in northwestern New Mexico. References below to "gross" wells and acres are to the interests of all persons owning interests therein, while references to "net" are to the interests of BROG (from which the Royalty was carved) in such wells and acres. Unless otherwise indicated, the following information in Item 2 is based upon data and information furnished to the Trustee by BROG. PRODUCING ACREAGE, WELLS AND DRILLING The Underlying Interests consist of working interests, royalty interests, overriding royalty interests and other contractual rights in 151,900 gross (119,000 net) producing acres in San Juan, Rio Arriba and Sandoval Counties of northwestern New Mexico. Based upon information received from the Trust's independent petroleum engineers, as of December 31, 2002, the Trust properties contain 3,738 gross (1,135 net) economic wells, including dual completions. Production from conventional gas wells is primarily from the Pictured Cliffs, Mesaverde and Dakota formations. During 1988, Southland Royalty began development of coal seam reserves in the Fruitland Coal formation. For additional information concerning coal seam gas, the "Description of the Properties" section of the Trust's Annual Report to security holders for the year ended December 31, 2002, is herein incorporated by reference. The Royalty conveyed to the Trust is limited to the base of the Dakota formation, which is currently the deepest significant producing formation under acreage affected by the Royalty. Rights to production, if any, from deeper formations are retained by BROG. In February 2002, BROG announced an estimated capital budget for the Underlying Properties of $17.1 million. During the year the estimate was initially reduced to $12.4 million and ultimately increased to $19.0 million. BROG's capital plan for the Underlying Properties for 2002 estimated 397 projects, including the drilling of 54 new wells operated by BROG and 26 wells operated by third parties. In 2002, BROG actually participated in 339 projects, including 41 new wells operated by BROG and 12 wells operated by third parties. BROG reported that the swings in the budget estimates related in large part to whether and when BROG was successful in obtaining the necessary governmental and landowner approvals to drill on a well-by-well basis. An aggregate of $21.5 million in capital expenditures were reported by BROG in calculating payments to the Trust for 2002. This amount included approximately $10.1 million attributable to the capital budgets for prior years. This occurs because projects within a given year's budget may extend into subsequent years, with capital expenditures attributable to those projects used in calculating distributable income to the Trust in 4 those subsequent years. Further, BROG's accounting period for capital expenditures runs through November 30 of each calendar year, such that capital expenditures incurred in December of each year are actually accounted for as part of the following year's capital expenditures. Also, for wells not operated by BROG, BROG's share of capital expenditures may not actually be paid by it until the year or years after those expenses were incurred by the operator. Capital expenditures of approximately $11.4 million for 2002 budgeted projects were used in calculating distributable income in calendar year 2002, and approximately $3.6 million in capital expenditures have been used in calculating distributions for the first three months of 2003. Therefore, an additional approximately $4.0 million in capital expenditures for 2002 projects remains to be spent. During 2002, in calculating the net proceeds to the Trust, BROG deducted approximately $21.5 million of capital expenditures for projects, including drilling and completion of 98 gross (30.05 net) conventional wells, recompletion of 36 gross (14.44 net) conventional wells, 13 gross (2.21 net) miscellaneous capital projects, one gross (.82 net) restimulation, one gross (.05 net) payadd, 16 gross (5.42 net) coal seam wells, 11 gross (1.45 net) miscellaneous coal seam capital projects, 14 gross (5.77 net) coal seam recompletions, five gross (.98 net) coal seam recavitations, three gross (.01 net) coal seam restimulations and facilities maintenance. There were 61 gross (24.49 net) new conventional wells, 20 gross (4.69 net) conventional well recompletions, 65 gross (19.82 net) miscellaneous conventional capital projects, four gross (1.41 net) coal seam wells, two gross (.99 net) coal seam recompletions, and five gross (1.72 net) miscellaneous coal seam capital projects in progress as of December 31, 2002. During 2001, in calculating the net proceeds to the Trust, BROG deducted approximately $33 million of capital expenditures for projects, including drilling and completion of 92 gross (36.33 net) conventional wells, recompletion of 33 gross (18.18 net) conventional wells, 13 gross (2.85 net) miscellaneous capital projects, three gross (2.34 net) restimulations, 56 gross (8.40 net) conventional payadds, ten gross (1.52 net) coal seam wells, four gross (1.61 net) coal seam well recompletions, one gross (.88 net) coal seam payadd, six gross (.04 net) coal seam recavitations and facilities maintenance. There were 100 gross (32.47 net) new conventional wells, 31 gross (13.47 net) conventional well recompletions, two gross (.87 net) miscellaneous conventional capital projects, nine gross (3.17 net) conventional payadds, 15 gross (1.09 net) conventional restimulations, 12 gross (5.36 net) coal seam wells, seven gross (4.11 net) coal seam recompletions, two gross (.02 net) coal seam restimulations and six gross (.29 net) miscellaneous coal seam capital projects in progress as of December 31, 2001. BROG has informed the Trust that its projections for capital expenditures for the Underlying Properties in 2003 is estimated at $14.1 million. BROG anticipates 351 projects, including the drilling of 38 new wells to be operated by BROG and 26 wells to be operated by third parties. Of the new BROG operated wells, 14 are projected to be conventional wells completed to the Pictured Cliffs, Mesaverde, and/or Dakota formations, and the remaining 24 are projected as coal seam gas wells to be completed in the Fruitland Coal formation. A total of 21 of the wells operated by third parties are projected to be conventional wells and the remaining five are to be coal seam wells. BROG projects approximately $10.5 million to be spent on new wells, and $3.6 million to be expended in working over existing wells and in the maintenance and improvement of production facilities. In October 2002, the New Mexico Oil Conservation Division approved reduced, 160-acre spacing in selected portions of the Fruitland Coal formation. BROG has informed the Trust that, principally as a result of this approval, its budget for 2003 reflects a focus on the Fruitland Coal formation. In February 2002, BROG informed the Trust that the New Mexico Oil Conservation Division had approved plans for 80-acre infill drilling of the Dakota formation in the San Juan Basin. The New Mexico Oil Conservation has asked BROG and other interested parties to study over the next year whether the change in spacing requirements should be expanded to cover other portions of that reservoir. Eighty-acre spacing has been permitted in the Mesaverde formation since 1997. BROG has previously informed the Trust that increases in its capital program, particularly in 2001 and 2002, were designed to offset the natural decline in production from the Underlying Properties. BROG has reported favorable results in this effort in that natural gas production for calendar year 2002 averaged 5 approximately 127 MMcf per day, as compared to average production of approximately 121 MMcf per day for calendar 2001, and 116 MMcf per day for calendar 2000. BROG indicates its budget for 2003 reflects continued significant development of properties in which the Trust's net overriding royalty interest is relatively high, a sustained focus on conventional formations, including infill drilling to the Mesaverde and Dakota formations, development of the Fruitland Coal formation and multiple formation completions. OIL AND GAS PRODUCTION The Trust recognizes production during the month in which the related net proceeds attributable to the Royalty are paid to the Trust. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2002 were as follows:
2002 2001 2000 --------------------- --------------------- --------------------- OIL OIL OIL (BBLS) GAS (MCF) (BBLS) GAS (MCF) (BBLS) GAS (MCF) ------- ----------- ------- ----------- ------- ----------- Production........... 40,215 19,584,056 42,056 19,272,021 47,441 20,317,750 Average Price........ $ 20.90 $ 2.32 $ 24.99 $ 4.61 $ 24.66 $ 2.99
PRICING INFORMATION Gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to the discussion contained herein under "Regulation" for information as to federal regulation of prices of oil and natural gas. Gas production from the properties from which the Royalty was carved totaled 46,206,298 Mcf during 2002. On September 4, 1996, the Trustee announced a settlement of litigation filed by the Trustee against BROG and Southland Royalty Company. In the settlement, agreement was reached, among other things, regarding marketing arrangements for the sale of those gas, oil and natural gas liquids products which are subject to the Royalty (the "Trust" gas, oil and/or natural gas liquids) as follows: (i) BROG agreed that all subsequent contracts for the sale of Trust gas would require the written approval of an independent gas marketing consultant acceptable to the Trust; (ii) BROG will continue to market the Trust oil and natural gas liquids but will make payments to the Trust based on actual proceeds from such sales, and BROG will no longer use posted prices as the basis for calculating proceeds to the Trust nor make a deduction for marketing fees associated with sales of oil or natural gas liquids products; and (iii) The independent marketer of the Trust gas is entitled to use of BROG's current gas transportation, gathering, processing and treating agreements with third parties, at least through the remainder of their primary terms. See Note 5 of Notes to Financial Statements of the Trust's Annual Report to security holders for the year ended December 31, 2002 for further discussion of this settlement and its impact on the Trust. BROG has entered into two contracts for the sale of all Trust gas. These contracts provide for (i) the sale of Trust gas in two packages to Duke Energy and Marketing, L.L.C. and PNM Gas Services, respectively, (ii) the delivery of Trust gas at various delivery points over a period commencing April 1, 2002, and ending March 31, 2004, and (iii) the sale of Trust gas at prices which fluctuate in accordance with published indices for gas sold in the San Juan Basin of New Mexico. Confidentiality agreements with purchasers of gas produced from the Underlying Properties prohibit public disclosure of certain terms and conditions of gas sales contracts with those entities, including specific pricing terms, gas receipt points, etc. Such disclosure could compromise the ability to compete effectively in the marketplace for the sale of gas produced from the Underlying Properties. 6 OIL AND GAS RESERVES The following are definitions adopted by the SEC and the Financial Accounting Standards Board which are applicable to terms used within this Item: "Estimated future net revenues" are computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. "Estimated future net revenues" are sometimes referred to in this Form 10-K as "estimated future net cash flows." "Present value of estimated future net revenues" is computed using the estimated future net revenues (as defined above) and a discount rate of 10%. "Proved reserves" are those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. "Proved developed reserves" are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. "Proved undeveloped reserves" are those proved reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. The independent petroleum engineers' reports as to the proved oil and gas reserves as of December 31, 2000, 2001 and 2002 were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 1999 to December 31, 2002 (in thousands):
CRUDE NATURAL OIL GAS (BBLS) (MCF) ------ -------- Reserves as of December 31, 1999............................ 450 214,215 ---- -------- Revisions of previous estimates............................. 199 73,803 Extensions, discoveries and other additions................. 80 36,207 Production.................................................. (47) (20,318) ---- -------- Reserves as of December 31, 2000............................ 682 302,907 ---- -------- Revisions of previous estimates............................. (272) (116,270) Extensions, discoveries and other additions................. 15 9,450 Production.................................................. (42) (19,272) ---- -------- Reserves as of December 31, 2001............................ 383 176,815 ---- -------- Revisions of previous estimates............................. 86 60,402 Extensions, discoveries and other additions................. 19 17,833 Production.................................................. (40) (19,584) ---- -------- Reserves as of December 31, 2002............................ 448 235,466 ---- --------
7 Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2002, 2001 and 2000 were as follows (in thousands):
CRUDE NATURAL OIL GAS (BBLS) (MCF) ------ ------- 2002........................................................ 415 209,665 2001........................................................ 356 162,577 2000........................................................ 624 277,459
Generally, the calculation of oil and gas reserves takes into account a comparison of the value of the oil or gas to the cost of producing those minerals, in an attempt to cause minerals in the ground to be included in reserve estimates only to the extent that the anticipated costs of production will be exceeded by the anticipated sales revenue. Accordingly, an increase in sales price and/or a decrease in production cost can itself result in an increase in estimated reserves and declining prices and/or increasing costs can result in reserves reported at less than the physical volumes actually thought to exist. The Financial Accounting Standards Board requires supplemental disclosures for oil and gas producers based on a standardized measure of discounted future net cash flows relating to proved oil and gas reserve quantities. Under this disclosure, future cash inflows are estimated by applying year-end prices of oil and gas relating to the enterprise's proved reserves to the year-end quantities of those reserves. Future price changes are only considered to the extent provided by contractual arrangements in existence at year-end. The standardized measure of discounted future net cash flows is achieved by using a discount rate of 10% a year to reflect the timing of future net cash flows relating to proved oil and gas reserves. Estimates of proved oil and gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables. Accordingly, under the allocation method used to derive the Trust's quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and gas reserves and estimated future net revenues. The 2002, 2001 and 2000 changes in the standardized measure of discounted future net cash flows related to future royalty income from proved reserves discounted at 10% are as follows (in thousands):
2002 2001 2000 -------- -------- -------- Balance, January 1................................... $173,846 $818,212 $229,721 Revisions of prior-year estimates, change in prices and other.......................................... 233,062 (652,337) 530,811 Extensions, discoveries and other additions.......... 25,642 7,519 94,753 Accretion of discount................................ 17,385 81,821 22,972 Royalty income....................................... (38,053) (81,369) (60,045) -------- -------- -------- Balance, December 31................................. $411,882 $173,846 $818,212 -------- -------- --------
Reserve quantities and revenues shown in the tables above for the Royalty were estimated from projections of reserves and revenues attributable to the combined BROG and Trust interests. Reserve quantities attributable to the Royalty were derived from estimates by allocating to the Royalty a portion of the total net reserve quantities of the interests, based upon gross revenue less production taxes. Because the reserve quantities attributable to the Royalty are estimated using an allocation of the reserves, any changes in prices or costs will result in changes in the estimated reserve quantities allocated to the Royalty. Therefore, the reserve quantities estimated will vary if different future price and cost assumptions occur. The future net cash flows were determined without regard to future federal income tax credits available to production from coal seam wells. December average prices of $3.75 per Mcf of conventional gas, $2.80 per Mcf of coal seam gas and $24.88 per Bbl of oil were used at December 31, 2002, in determining future net revenue. The upward revision in reserve quantities for 2002 as compared to 2001 is primarily due to significantly higher oil and gas prices in December 2002 as compared to December 2001. 8 December average prices of $1.96 per Mcf of conventional gas, $1.42 per Mcf of coal seam gas and $15.79 per Bbl of oil were used at December 31, 2001, in determining future net revenue. The downward revision in reserve quantities for 2001 as compared to 2000 is primarily due to significantly lower oil and gas prices in December 2001 as compared to December 2000. December average prices of $6.18 per Mcf of conventional gas, $4.03 per Mcf of coal seam gas and $24.67 per Bbl of oil were used at December 31, 2000, in determining future net revenue. The following presents estimated future net revenues and present value of estimated future net revenues attributable to the Royalty for each of the years ended December 31, 2002, 2001 and 2000 (in thousands except amounts per Unit):
2002 2001 2000 -------------------- -------------------- --------------------- ESTIMATED ESTIMATED ESTIMATED FUTURE PRESENT FUTURE PRESENT FUTURE PRESENT NET VALUE AT NET VALUE AT NET VALUE AT REVENUE 10% REVENUE 10% REVENUE 10% --------- -------- --------- -------- ---------- -------- Total Proved................ $737,639 $411,882 $290,582 $173,846 $1,580,837 $818,212 Proved Developed............ $661,634 $378,285 $266,834 $164,164 $1,445,557 $752,825 Total Proved Per Unit....... $ 15.83 $ 8.84 $ 6.23 $ 3.73 $ 33.92 $ 17.55
Proved reserve quantities are estimates based on information available at the time of preparation and such estimates are subject to change as additional information becomes available. The reserves actually recovered and the timing of production of those reserves may be substantially different from the above estimates. Moreover, the present values shown above should not be considered 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 and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry. Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability of production. The effect of these regulations is to limit the amounts of natural gas and oil that BROG can produce and to limit the number of wells or the locations at which BROG can drill. FEDERAL NATURAL GAS REGULATION The transportation and sale for resale of natural gas in interstate commerce, historically, have been regulated pursuant to several laws enacted by Congress and the regulations promulgated under these laws by the Federal Energy Regulatory Commission ("FERC") and its predecessor. In the past, the federal government has regulated the prices at which gas could be sold. Congress removed all non-price controls affecting wellhead sales of natural gas effective January 1, 1993. Congress could, however, reenact price controls in the future. Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major 9 regulatory changes have been implemented by Congress and FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. Additional proposals and proceedings that might affect the natural gas industry are considered from time to time by Congress, FERC, state regulatory bodies and the courts. The Trust cannot predict when or if any such proposals might become effective, or their effect, if any, on the Trust. The natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less stringent regulatory approach pursued over the last decade by FERC and Congress will continue. Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. The ability to transport and sell petroleum products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines. SECTION 29 TAX CREDIT The Trust began receiving royalty income from coal seam gas wells in 1989. Under Section 29 of the Internal Revenue Code, coal seam gas production from wells drilled prior to January 1, 1993 (including certain wells recompleted in coal seams formations thereafter), generally qualifies for the federal income tax credit for producing non-conventional fuels if such production and the sale thereof occurs before January 1, 2003. Thus, under current law, coal seam gas production after December 31, 2002 will not qualify for the Section 29 credit. For 2001, this tax credit was approximately $1.08 per MMBtu. For 2002, the amount of the credit will be determined by the Treasury Department no later than April 1, 2003, and, based on historical trends, is expected to approximate (within a 2-3% range) the 2001 credit. To benefit from the credit, each Unit Holder must determine from the tax information he receives from the Trust his pro rata share of qualifying production of the Trust, based upon the number of Units owned during each month of the year, and the amount of available credit per MMbtu for the year, and then apply the tax credit against his own income tax liability, but such credit may not reduce his regular tax liability (after the foreign tax credit and certain other nonrefundable credits) below his tentative minimum tax. Section 29 also provides that any amount of Section 29 credit disallowed for the tax year solely because of this limitation will increase his credit for prior year minimum tax liability, which may be carried forward indefinitely as a credit against the taxpayer's regular tax liability, subject, however, to the limitations described in the preceding sentence. There is no provision for the carryback or carryforward of the Section 29 credit in any other circumstances. BROG provides the Trustee with certain Section 29 tax credit information, including qualifying coal seam volumes produced from Underlying Properties. In 1999, the Tenth Circuit Court upheld the position of the IRS and the Tax Court that nonconventional fuel such as coal seam gas does not qualify for the Section 29 credit unless the producer received a formal certification from FERC. FERC's certification authority expired effective January 1, 1993. However, on July 14, 2000, FERC issued a final ruling amending its regulations to reinstate certain regulations involving well category determinations for all wells and tight formation areas that could qualify for the Section 29 tax credit. BROG has informed the Trustee that it will seek certification of all qualified wells and that two additional wells were certified in 2002. OTHER REGULATION The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, environmental protection, occupational safety, resource conservation and equal employment opportunity. 10 ITEM 3. LEGAL PROCEEDINGS SETTLEMENTS As part of the September 4, 1996 settlement of the litigation filed by the Trustee on June 4, 1992, against BROG and Southland Royalty Company, the Trust was entitled to certain adjustments (the "Val Verde Credit") that represented cost reductions favorable to the Trust in the charges for coal seam gas gathered and treated on BROG's Val Verde system. The settlement provided that the Val Verde Credit was applicable until the later of July 1, 2002 or until BROG no longer owned the Val Verde facility. By correspondence dated July 15, 2002, BROG notified the Trustee of the sale of the Val Verde facility to TEPPCO Partners, L.P. effective July 1, 2002. Accordingly, effective July 1, 2002, the calculation of net proceeds for gas gathered and treated at the Val Verde facility no longer includes the Val Verde Credit. The total annual amount of the Val Verde Credit has been estimated by the Trust's joint interest auditors as approximately $2.0 million. The loss of the Val Verde Credit will result in increased costs allocated to the Trust for coal seam gas gathered and treated on the Val Verde system and accordingly, will decrease the royalty income received by the Trust. An administrative claim was initiated on March 17, 1997, by the Mineral Management Service of the United States Department of the Interior (the "MMS") against BROG regarding a gas contract settlement dated March 1, 1990, between BROG and certain other parties thereto. The claim alleged that additional royalties were due on production from federal and Indian leases in the State of New Mexico on properties burdened by the Trust. On December 3, 2001, BROG settled this claim by paying the Jicarilla Apache Nation the sum of $2,853,974 and the MMS the sum of $1,224,043. MMS also retained certain overpayments by BROG in the amount of $1,127,623 as part of the settlement. Certain properties included in this settlement are burdened by the Royalty. BROG has offset the entire $2,853,974 Jicarilla component of the settlement against amounts otherwise distributed in payment of the Royalty, and has informed the Trust that the $1,224,043 paid to the MMS is also allocable to the Royalty. BROG has indicated that it does not appear that any of the $1,127,623 in overpayments retained by the MMS is attributable to the Royalty. In another proceeding involving BROG and the Jicarilla Apache Nation, the MMS entered an Order to Perform on June 10, 1998, stating that, in valuing production for royalty purposes, BROG must perform, among other things, a "dual accounting" calculation (i.e., compute royalties on the greater of the value of gas prior to processing or the combined value of processed residue gas and plant products plus the value of any condensate recovered downstream without processing). In December 2000, BROG and the Jicarilla Apache Nation entered into a settlement resolving the issues associated with the dual accounting calculation. Under the settlement, BROG paid $3,260,366 to the Jicarilla Apache Nation. BROG has allocated $1,978,182 of the settlement payment to the Royalty. Beginning in May 2002, BROG deducted the lesser of $1 million or 50% of the monthly net proceeds from the monthly net proceeds otherwise payable to the Trust until an aggregate of $3,624,117 was deducted. BROG deducted $1 million from each of the monthly net proceeds payments to the Trust in May, June and July of 2002, and the balance in August of 2002. These deductions represented the Trust's share of the settlements. In June 2000, the Trust and BROG entered into a partial settlement of claims relating to a gas imbalance with respect to production from mineral properties currently operated by BROG. Under the terms of the partial settlement, BROG paid the Trust $3,490,000 to settle the imbalance insofar as it relates to some of the wells located on the Underlying Properties. The remainder of the imbalance is to be addressed through volume adjustments whereby the Trust's Royalty will be increased by the proceeds from 50% of the overproduced parties' interest, on a monthly basis, until the imbalance is corrected. The Trustee and its consultants remain in communication with BROG in order to determine the estimated value of the volume adjustments and the time during which the remainder of the imbalance will be corrected. BROG indicates that the volume adjustment commenced in August 2000. The Trust's consultants continue to monitor those adjustments. 11 ADMINISTRATIVE PROCEEDINGS The following information was provided to the Trust by BROG. Please note that the proceedings described below apply to the collective interest of BROG and the Trust. BROG is not able to estimate the amount of any potential loss to the Trust in each of the outstanding proceedings, or the portion of any such potential loss that would be allocated to the Royalty. MMS PROCEEDINGS Blanco Pool. This appeal arises from a MMS Demand Letter dated October 20, 1995, and bears MMS Appeal Docket No. MMS-95-0740. The demand letter challenges the "valuation benchmark" utilized by BROG for gas sold by BROG from the "Blanco Pool" during the audit period of January 1, 1989 through December 31, 1991. BROG paid royalties on sales to its marketing affiliate based on "gross proceeds" received by BROG from its affiliate. The demand letter states that BROG paid incorrectly under MMS regulations. The MMS methodology in calculating the amounts demanded does not attempt to trace resale proceeds. Instead, MMS' auditors use published index prices at pipeline interconnect points in the San Juan Basin as a proxy for actual comparable sales, and net out certain actual costs to move the gas to those index points. While BROG had deducted prevailing field transportation rates in computing its monthly prices in the San Juan Basin, the auditors limited the deduction to the actual rate paid to El Paso Natural Gas under a "backhaul" agreement. The demand letter directs BROG to pay additional royalties of $518,304, to recalculate royalties in accordance with the MMS' interpretation of the regulations and to pay the difference between total royalty due and royalty paid. Affiliate Proceeds Demand -- Conventional Gas. This appeal arises from a MMS demand letter dated June 9, 1997, and bears MMS Appeal Docket No. MMS-97-0168. The demand letter is a blanket demand relating to all of BROG's non-coalbed methane gas production nationwide for the audit period of January 1, 1989 through December 31, 1994. The demand letter is based primarily on the MMS theory that royalties are to be based on BROG's marketing affiliate gross proceeds rather than BROG's gross proceeds (e.g. the affiliate resale proceeds issue). The demand letter directs BROG to recalculate its royalties on these sales using a netback calculation of the proceeds of the affiliate, and pay the difference between total royalties due under such calculation and the royalties actually paid by BROG. This demand letter is in furtherance of the demand letter described in the prior paragraph. Coalbed Methane. This appeal arises from a MMS demand letter dated October 28, 1996, and bears MMS Appeal Docket No. MMS-96-0437. The demand letter relates to BROG's coalbed methane production from the Northeast Blanco Unit for the audit period of May 1, 1990 through December 31, 1993, and from the San Juan 30-6 Unit for the audit period of January 1, 1989 through December 31, 1991. Like the Blanco Pool demand letter, the demand letter does not attempt to trace resale proceeds. The issues are whether MMS should bear its share of CO(2) extraction costs and, if so, whether the costs should be based on market rates or actual costs of the system, and whether MMS' share of transportation costs (which MMS does not dispute it must bear) should be based on market rates or actual costs of the system. BROG is directed to pay additional royalties of $3,600,584 for underpayment of royalty for gas produced from the units mentioned above, to recalculate royalties for gas produced from other federal leases in accordance with MMS' interpretation of the regulations and to pay the difference between total royalty due and royalty paid. Due to the similarity of the claims in the Blanco Pool, Affiliate Proceeds Demand and the Coalbed Methane administrative appeals, to the claims in the suits in the In re Natural Gas Royalties qui tam litigation described below, settlement discussions between BROG and the federal government in the gas qui tam litigation will, if successful, include the settlement of each of the MMS Proceedings. JICARILLA INDIAN TRIBE PROCEEDINGS This appeal arises from an MMS Order to Perform dated June 10, 1998. The Order to Perform states that, in valuing production for royalty purposes, BROG must, among other things, perform a major portion analysis (i.e., calculate value on the highest price paid or offered for a major portion of the gas produced from 12 the field where the leased lands are situated). BROG believes that producers do not have access to prices received by other producers in a field, so a major portion calculation must be done by MMS. LITIGATION GRYNBERG LITIGATION In September 1998, BROG was advised by the United States Department of Justice under an order of confidentiality that a lawsuit styled United States of America ex rel. Jack J. Grynberg v. Burlington Resources Oil & Gas, et al., Civil Action No. 97-CV-189 and 190, United States District Court for the District of Wyoming, had been filed under seal pursuant to the qui tam provisions of the civil federal False Claims Act, and that seventy-seven similar cases had been filed by the plaintiff against other companies. The complaint alleges that BROG engaged in the mismeasurement of volumes and wrongful analysis of heating content of natural gas and engaged in other activities, including the sale of natural gas to affiliated companies, which resulted in the underpayment of royalties to the United States. The government investigated the plaintiff's claims, and in May 1999 issued notice that the United States would not intervene in the case. The lawsuits have been unsealed by the court and the plaintiff has served the complaint on BROG. This claim was subsequently consolidated into a multi-district litigation proceeding as described below. IN RE NATURAL GAS ROYALTIES QUI TAM LITIGATION On March 28, 2000, the United States District Court for the Eastern District of Texas, Lufkin Division, ordered that the first amended complaint in the case of United States ex rel. M. Glenn Osterhoudt, III v. Amerada Hess, et al., Civil Action No. 9:98CV101, in the United States District Court for the Eastern District of Texas, Lufkin Division, and the second amended complaint in the case of United States of America ex rel. Harrold E. (Gene) Wright v. Agip Petroleum Burlington, et al., Civil Action No. C-5:96CV243 be unsealed and served upon defendants, including BROG. In these lawsuits, the plaintiffs have alleged violations of the civil False Claims Act. Plaintiffs contend that defendants underpaid royalties on natural gas and natural gas liquids produced on federal and Indian lands through the use of below-market prices, improper deductions, improper measurement techniques and transactions with affiliated companies. The United States has filed an intervention in these cases as to some of the defendants, including BROG. In July 2000, the United States District Court for the District of New Mexico unsealed and BROG was served with the petition in United States of America ex rel. Mark A. Perry v. BROG Resources, Inc., et al., Civil Action No. 9:00CV197, in the United States District Court for the District of New Mexico, wherein plaintiff alleges violations of the civil False Claims Act. The plaintiff claims that BROG understated the value of natural gas and natural gas liquids produced on federal and Indian lands in connection with its computation and reporting of royalty payments. The United States has elected to intervene in this case, but a complaint has not been served upon BROG. In October 2000, the federal Judicial Panel on Multidistrict Litigation ordered that the Wright and Osterhoudt lawsuits be transferred to the United State District Court for the District of Wyoming for inclusion with the Grynberg lawsuit described above in multidistrict litigation proceedings. A similar order was issued in December 2000 transferring the Perry lawsuit. These cases have been consolidated for pre-trial proceedings in the matter styled In re Natural Gas Royalties Qui Tam Litigation, MDL-1293, United States District Court for the District of Wyoming. If successful, this litigation could result in a decrease in royalty income received by the Trust. At this time, no estimate can be made as to the amount of any potential loss in this litigation, or the portion of any such potential loss that would be allocated to the Trust's interest. Any proposed allocation of loss to the Trust will be reviewed by the Trust's consultants. QUINQUE LITIGATION In September 1999, BROG was served with a class action petition styled Quinque Operating Company on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, 13 Kansas, naming certain of its current or former affiliates as defendants, along with hundreds of other gas production and gas pipeline companies. On February 21, 2002, the District Court granted leave for plaintiffs to file a third amended class action petition substituting in new class representative plaintiffs thereby changing the style of the case to Will Price, Stixon Petroleum, Inc. and Thomas F. Boles on behalf of Gas Producers v. Gas Pipelines, et al., Case No. 99 C 30, in the District Court of Stevens County, Kansas. The petition alleges that the defendants engaged in the mismeasurement of volumes and wrongful analysis of heating content of natural gas and engaged in other activities which resulted in the underpayment of revenue owed to working interest owners, royalty interest owners, overriding royalty interest owners and state taxing authorities. If successful, this litigation could result in a decrease in royalty income received by the Trust. At this time, no estimate can be made as to the amount of any loss in this litigation, or the portion of any such potential loss that would be allocated to the Trust. Any proposed allocation of loss to the Trust will be reviewed by the Trust's consultants. 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, 2002. 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, 2002, is herein incorporated by reference. The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans. ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31 ------------------------------------------------------------------- 2002 2001 2000 1999 1998 ----------- ----------- ----------- ----------- ----------- Royalty income.............. $38,053,281 $81,368,723 $60,044,773 $32,626,966 $30,317,860 Distributable income........ 36,417,967 80,126,202 59,188,932 31,795,667 29,498,402 Distributable income per Unit...................... 0.781354 1.719123 1.269909 0.682182 0.635039 Distributions per Unit...... 0.781354 1.719123 1.269909 0.682182 0.635039 Total assets, December 31... 37,972,696 38,051,369 47,659,746 49,048,652 53,753,582
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION The "Description of the Properties," "Trustee's Discussion and Analysis" and "Results of the 4th Quarters of 2002 and 2001" at pages 5 through 9 of the Trust's Annual Report to security holders for the year ended December 31, 2002, are herein incorporated by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Trust invests in no derivative financial instruments, and has no foreign operations or long-term debt instruments. The Trust is a passive entity and 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 14 currencies which could expose the Trust or Unit Holders to any foreign currency related market risk. The Trust does not market the Trust gas, oil and/or natural gas liquids. BROG is responsible for such marketing. ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Financial Statements of the Trust and the notes thereto at page 10 et seq., of the Trust's Annual Report to security holders for the year ended December 31, 2002, are herein incorporated by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE See information contained in the Trust's Form 8-K, dated July 17, 2001, reporting a change in accountants. PART III ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT 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. ITEM 11. EXECUTIVE COMPENSATION The Trust has no directors, executive officers or employees. Accordingly, the Trust does not maintain any equity compensation plans and there are no Units reserved for issuance under any such plans. During the year ended December 31, 2002, the Trustee received total remuneration as follows:
NAME OF INDIVIDUAL OR NUMBER OF CAPACITIES IN CASH PERSONS IN GROUP WHICH SERVED COMPENSATION ------------------------------- ------------- ------------ Bank One, N.A.(1).......................................... Trustee $148,399(3) TexasBank(2)............................................... Trustee $ 44,316(3)
--------------- (1) During 2002, Bank One, N.A. served as Trustee for the period January 1, 2002 through September 30, 2002. (2) During 2002, TexasBank served as Trustee for the period September 30, 2002 to December 31, 2002. (3) Under the Trust Indenture, the Trustee is entitled to an administrative fee for its administrative services and the preparation of quarterly and annual statements of: (i) 1/20 of 1% of the first $100 million of the annual gross revenue of the Trust, and 1/30 of 1% of the annual gross revenue of the Trust in excess of $100 million and (ii) the Trustee's standard hourly rates for time in excess of 300 hours annually. Beginning January 1, 2003, in no case will the administrative fee due under items (i) and (ii) above be less than $36,000 per year (as adjusted annually to reflect the increase (if any) in the Producers Price Index as published by the U.S. Department of Labor, Bureau of Labor Statistics). 15 ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED SECURITY HOLDER MATTERS (a) Security Ownership of Certain Beneficial Owners. The following table sets forth, as of March 23, 2003, information with respect to each person known to own beneficially more than 5% of the outstanding Units of the Trust:
AMOUNT AND NATURE OF BENEFICIAL NAME AND ADDRESS OWNERSHIP PERCENT OF CLASS ---------------- -------------------- ---------------- Alpine Capital, L.P.(1).............................. 10,599,200 Units 22.7% 201 Main Street, Suite 3100 Fort Worth, Texas 76102 Societe General Asset Management Corp.(2)............ 5,180,000 Units 11.1% 1221 Avenue of the Americas New York, New York 10020 Capital Group International, Inc.(3)................. 3,040,770 Units 6.5% Capital Guardian Trust Company 11100 Santa Monica Blvd Los Angeles, CA 90025 McMorgan and Company(4).............................. 3,000,000 Units 6.4% 1 Bush Street, Suite 800 San Francisco, CA 94104
--------------- (1) This information was provided to the Trust on Amendment Number 29 to Schedule 13D, dated March 5, 2003, as filed with the SEC by Alpine Capital, L.P. ("Alpine"), which indicated that these Units were beneficially owned by Alpine. Robert W. Bruce, III and Algenpar, Inc., are general partners of Alpine and have shared power to vote and dispose of the Units held by Alpine. The Amendment Number 27 to Schedule 13D may be reviewed for more detailed information concerning the matters summarized herein. (2) This information was provided to the Trust on Amendment Number 3 to Schedule 13G, dated January 6, 1999, as filed with the SEC. The Amendment Number 3 to Schedule 13G may be reviewed for more detailed information concerning the matters summarized herein. (3) This information was provided to the Trust in Amendment Number 5 to Schedule 13G dated December 31, 2002. Capital Group International, Inc. and Capital Guardian Trust Company each reported sole voting power over 2,131,440 Units and sole dispositive power over 3,040,770 Units. The Amendment Number 5 to Schedule 13G may be reviewed for more detailed information concerning the matters summarized herein. (4) This information was provided to the Trust in a Schedule 13G dated July 12, 1999, as filed with the SEC. The Schedule 13G may be reviewed for more detailed information concerning the matters summarized herein. (b) Security Ownership of Trustee. As of December 31, 2002, TexasBank owned no Units. 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 year ended December 31, 2002 and Item 12(b) for information concerning Units owned by TexasBank. ITEM 14. CONTROLS AND PROCEDURES The Trust maintains a system of disclosure controls and procedures that is designed to provide reasonable assurance that information required to be disclosed in the Trust's filings under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported, within the time periods specified in the Commission's 16 rules and forms. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the Trust is accumulated and communicated by BROG to the Trustee and its employees who participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure. Due to the pass-through nature of the Trust, BROG provides much of the information disclosed in this Form 10-K/A and the other periodic reports filed by the Trust with the SEC. The Trustee receives periodic updates from BROG regarding activities related to the Trust. Accordingly, the Trust's ability to timely report certain information required to be disclosed in the Trust's periodic reports is dependent on BROG's timely delivery of such information to the Trust. In order to help ensure the accuracy and completeness of the information required to be disclosed in the Trust's periodic reports, the Trust employs independent public accountants, joint interest auditors, marketing consultants, attorneys and petroleum engineers. These outside professionals assist the Trustee in reviewing and compiling this information for inclusion in this Form 10-K/A and the other periodic reports provided by the Trust to the SEC. The Trustee has evaluated the Trust's disclosure controls and procedures within the 90 days prior to the filing of this Annual Report on Form 10-K/A and has determined that, subject to BROG's delivery of timely and accurate information to the Trust, such disclosure controls and procedures are effective. The Trustee has not reviewed the Trust's disclosure controls and procedures in concert with management, a board of directors or an independent audit committee. The Trust does not have, nor does the Trust Indenture provide for, officers, a board of directors or an independent audit committee. Subsequent to the Trustee's evaluation, there were no significant changes in internal controls or other factors that could significantly affect internal controls, including any corrective actions with regard to significant deficiencies and material weaknesses. 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: FINANCIAL STATEMENTS Included in Part II of this Report by reference to the Annual Report of the Trust for the year ended December 31, 2002: Independent Auditors' Reports Statements of Assets, Liabilities and Trust Corpus Statements of Distributable Income Statements of Changes in Trust Corpus Notes to Financial Statements FINANCIAL STATEMENT SCHEDULES Financial statement schedules are omitted because of the absence of conditions under which they are required or because the required information is given in the financial statements or notes thereto. REPORTS ON FORM 8-K On October 1, 2002, the Trust filed a Current Report on Form 8-K, dated September 30, 2002, disclosing under Item 5 that it had issued a press release announcing that at a special meeting the Unit Holders had (a) appointed TexasBank as the successor Trustee of the Trust and (b) approved three separate groups of amendments to the Original Indenture. 17 EXHIBITS
EXHIBIT NUMBER NUMBER DESCRIPTION ------- ------------------ (4)(a) -- Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee) heretofore filed as Exhibit 99.2 of the Trust's Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.* (b) -- Net Overriding Royalty Conveyance from Southland Royalty Company to the Forth Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (c) -- Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank heretofore filed as Exhibit 4(c) to the Trust's Quarterly Report on Form 10-Q with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.* (13) -- Registrant's Annual Report to security holders for fiscal year ended December 31, 2002, heretofore filed as Exhibit 13 to the Trust's Annual Report on Form 10-K for the fiscal year ended December 31, 2002, and filed with the SEC on March 27, 2003, is incorporated herein by reference. (23.1) -- Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
--------------- * A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116. ** Filed herewith. 18 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. TEXASBANK, AS TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST /s/ LEE ANN ANDERSON -------------------------------------- Lee Ann Anderson Vice President and Trust Officer Date: April 1, 2003 (The Trust has no directors or executive officers) 19 CERTIFICATION I, Lee Ann Anderson, certify that: 1. I have reviewed this annual report on Form 10-K/A of San Juan Basin Royalty Trust, for which TexasBank acts as Trustee; 2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report; 3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, distributable income and changes in trust corpus of the registrant as of, and for, the period presented in this annual report; 4. I am responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14), or for causing such procedures to be established and maintained, for the registrant and I have: a) designed such disclosure controls and procedures, or caused such controls and procedures to be designed, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to me by others within those entities, particularly during the period in which this annual report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the "Evaluation Date"); and c) presented in this annual report my conclusions about the effectiveness of the disclosure controls and procedures based on my evaluation as of the Evaluation Date; 5. I have disclosed, based on my most recent evaluation, to the registrant's auditors: a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves persons who have a significant role in the registrant's internal controls; and 6. I have indicated in this annual report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of my most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. In giving the certifications in paragraphs 4, 5 and 6 above, I have relied to the extent I consider reasonable on information provided to me by Burlington Resources Oil & Gas Company LP. TEXASBANK, AS TRUSTEE FOR THE SAN JUAN BASIN ROYALTY TRUST By: /s/ LEE ANN ANDERSON ------------------------------------ Lee Ann Anderson Vice President and Trust Officer Date: April 1, 2003 20 EXHIBIT INDEX
EXHIBIT NUMBER NUMBER DESCRIPTION ------- ------------------ (4)(a) -- Amended and Restated Royalty Trust Indenture, dated September 30, 2002 (the original Royalty Trust Indenture, dated November 1, 1980 having been entered into between Southland Royalty Company and The Fort Worth National Bank, as Trustee) heretofore filed as Exhibit 99.2 of the Trust's Current Report on Form 8-K filed with the SEC on October 1, 2002, is incorporated herein by reference.* (b) -- Net Overriding Royalty Conveyance from Southland Royalty Company to the Forth Worth National Bank, as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K filed with the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (c) -- Assignment of Net Overriding Interest (San Juan Basin Royalty Trust), dated September 30, 2002, between Bank One, N.A. and TexasBank heretofore filed as Exhibit 4(c) to the Trust's Quarterly Report on Form 10-Q with the SEC for the quarter ended September 30, 2002, is incorporated herein by reference.* (13) -- Registrant's Annual Report to security holders for fiscal year ended December 31, 2002, heretofore filed as Exhibit 13 to the Trust's Annual Report on Form 10-K for the fiscal year ended December 31, 2002, and filed with the SEC on March 27, 2003, is incorporated herein by reference. (23.1) -- Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
--------------- * A copy of this Exhibit is available to any Unit Holder (free of charge) upon written request to the Trustee, TexasBank, 2525 Ridgmar Boulevard, Suite 100, Fort Worth, Texas 76116. ** Filed herewith.