10-K405 1 d85619e10-k405.txt FORM 10-K FOR FISCAL YEAR END DECEMBER 31, 2000 1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 ---------- FORM 10-K (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, 2000, 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 San Juan Basin Royalty Trust Indenture) TEXAS 75-6279898 (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) BANK ONE, NA 76113 CORPORATE TRUST DEPARTMENT (Zip Code) P.O. BOX 2604 FORT WORTH, TEXAS (Address of principal executive offices) (817) 884-4630 (Registrant's telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: NAME OF EACH EXCHANGE ON TITLE OF EACH CLASS 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. [X] At March 28, 2001, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding with an aggregate market value on that date of $726,165,042. 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 and 8; "Results of the 4th Quarters of 2000 and 1999" at page 9; 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 10 et seq., in registrant's Annual Report to Unit holders for fiscal year ended December 31, 2000 are incorporated herein by reference for Item 2 (Properties), Item 3 (Legal Proceedings), 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. ================================================================================ 2 PART I ITEM 1. BUSINESS The San Juan Basin Royalty Trust (the "Trust") is an express trust created under the laws of the state of Texas by the "San Juan Basin Royalty Trust Indenture" (the "Trust Indenture") entered into on November 3, 1980, between Southland Royalty Company ("Southland Royalty") and The Fort Worth National Bank, a banking association organized under the laws of the United States, as Trustee. The Trustee is now Bank One, NA The principal office of the Trust (sometimes referred to herein as the "Registrant") is located at 500 Throckmorton Street, Fort Worth, Texas 76102, Attention: Corporate Trust Department (telephone number 817/884-4630). 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 in the San Juan Basin of northwestern New Mexico. The conveyance of this 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 one Unit for each share of the common stock of Southland Royalty then held. 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, El Paso Natural Gas Company ("El Paso"), Meridian Oil, Inc. ("MOI") and Meridian Oil Trading Inc. ("MOTI") also became indirect subsidiaries 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 and MOI survived and succeeded to the ownership of all of the assets, has the rights, powers and privileges and assumed all of the liabilities and obligations of Southland Royalty. Subsequent to the merger, MOI changed its name to Burlington Resources Oil & Gas Company ("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 interests from which the Royalty was carved) from the sale of the production attributable to the interests in properties from which the Royalty was carved (the "Underlying Properties"), 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 1 3 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 Properties are operated by BROG with the obligation to conduct its operations in accordance with reasonable and prudent business judgment and good oil and gas field practices. As operator, BROG has the right to abandon any well when in its opinion such well ceases to produce or is not capable of producing oil and gas in paying quantities. BROG also is responsible, to the extent it has the legal right to do so 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. As a result of the settlement of the Litigation (as hereinafter defined), agreement was reached, among other things, regarding the marketing of such production. See Note 5 of Notes to Financial Statements incorporated herein by reference. 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) 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 being held by the Trustee as a reserve for liabilities or contingencies (which reserves may be established by the Trustee in its discretion) or pending distribution is placed, in the Trustee's discretion, in obligations issued by (or unconditionally guaranteed by) the United States or any agency thereof, repurchase agreements secured by obligations issued by the United States or any agency thereof, 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 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 75% net overriding royalty conveyed to the Trust was carved out of Southland Royalty's (now BROG's) working interest and royalty interests in 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. 2 4 PRODUCING ACREAGE, WELLS AND DRILLING The Underlying Properties consist of working interests and royalty interests 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, the Trust properties contain 3,363 gross (975 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, 2000, 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. During 2000, in calculating the net proceeds to the Trust, BROG deducted approximately $25.6 million of capital expenditures for the drilling and completion of 45 gross (25.45 net) conventional wells, recompletion of 15 gross (6.80 net) conventional wells, 12 gross (6.75 net) coal seam wells, 4 gross (.17 net) coal seam well recompletions, and 41 gross (.24 net) coal seam recavitations. There were 124 gross (36.15 net) new conventional wells, 59 gross (21.37 net) conventional well recompletions, 10 gross (2.14 net) coal seam wells, 12 gross (1.64 net) coal seam recompletions, and 4 gross (.03 net) coal seam recavitations in progress as of December 31, 2000. During 1999, in calculating the net proceeds to the Trust, BROG deducted approximately $10.5 million of capital expenditures for the drilling and completion of 71 gross (7.22 net) conventional wells, recompletion of four gross (1.36 net) conventional wells, three gross (.93 net) coal seam wells, one gross (.54 net) coal seam well recompletions, and 10 gross (.07 net) coal seam recavitations. There were 53 gross (20.14 net) new conventional wells, 25 gross (3.77 net) conventional well recompletions, three gross (.39 net) coal seam wells, seven gross (.79 net) coal seam recompletions, and 38 gross (.75 net) coal seam recavitations in progress as of December 31, 1999. BROG announced that the New Mexico Oil Conservation Division has approved plans for 80-acre infill drilling of the Mesaverde formation in the San Juan Basin. The Mesaverde formation was originally developed in the 1950's on 320-acre spacing, with infill drilling initiated in the early 1970's on 160-acre spacing. In 1994, BROG undertook an extensive study of the Mesaverde formation. Results indicated that downspaced drilling (infill drilling) on 80-acre spacing could significantly increase recoverable gas reserves in this massive reservoir. A pilot program began in 1997 and was expanded in 1998 to include two additional areas. BROG informed the Trust that its goal in increasing capital expenditures to $25.6 million in 2000 as compared to the $10.5 million in capital expenditures passed through to the Trust in 1999, was to offset the natural decline in production from the Underlying Properties. BROG announced that natural gas production from the Underlying Properties averaged approximately 116 MMcf per day in calendar 2000 as compared to approximately 113 MMcf per day in 1999, and that production was approximately 120 MMcf per day in October of 2000. BROG has informed the Trust that capital expenditures for 2001 are estimated to be $30.2 million. BROG anticipates 406 new capital projects for 2001, including the drilling of 49 new wells to be operated by BROG and 40 wells operated by third parties. Of the new, BROG-operated wells, 42 are projected to be conventional wells completed to the Pictured Cliffs, Mesaverde, and/or Dakota formations, and the remaining seven are projected as coal seam gas wells to be completed in the Fruitland Coal formation. BROG projects approximately $17,500,000 as the cost of the new wells, with the $12,700,000 balance to be expended in working over existing wells and in the maintenance and improvement of production facilities. BROG reports that the Bureau of Land Management ("BLM") has undertaken an environmental impact study of the entire San Juan Basin such that new drilling activity located more than 300 feet from an existing road now requires an additional level of regulatory approval on a well-by-well basis. Depending upon the results of BROG's requests for approval to drill, the capital budget for 2001 may range from a low of approximately $25,000,000 to a high 3 5 of approximately $35,000,000, depending in large part upon the total number of new wells for which the BLM issues approvals to drill. BROG indicates its budget for 2001 reflects continued, significant development of properties in which the Trust's net overriding royalty interest is relatively high, as well as a sustained focus on conventional formations, including infill drilling to the Mesaverde formation, and multiple formation completions. OIL AND GAS PRODUCTION The Trust recognizes production during the month in which the related distribution is received. Production of oil and gas and related average sales prices attributable to the Royalty for the three years ended December 31, 2000 were as follows:
2000 1999 1998 --------------------------------- --------------------------------- --------------------------------- OIL GAS OIL GAS OIL GAS (Bbls) (Mcf) (Bbls) (Mcf) (Bbls) (Mcf) -------------- -------------- -------------- -------------- -------------- -------------- Production ....... 47,441 20,317,750 35,341 19,527,666 37,067 18,904,906 Average Price .... $ 24.66 $ 2.99 $ 14.41 $ 1.78 $ 13.55 $ 1.75
PRICING INFORMATION Gas produced in the San Juan Basin is sold in both interstate and intrastate commerce. Reference is made to "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 42,220,260 Mcf during 2000. On September 4, 1996, the Trustee announced the settlement of the litigation (the "Litigation") filed by the Trustee against BROG and Southland Royalty Company. The Litigation, which was filed in the state district court of Santa Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996. 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, except for a pre-existing contract which has since expired, 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. 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 access to BROG's current gas transportation, gathering, processing and treating agreements with third parties through the remainder or their primary terms. The gas purchase contracts described in subparagraph (i), above, were continued, by agreement of the parties until December 31, 1997. Effective January 1, 1998, all volumes of Trust gas became subject to the terms of a Natural Gas Sales and Purchase Contract between BROG and El Paso. That contract was for a term of two years through and including December 31, 1999 and provided for the sale of Trust gas at prices which will fluctuate in accordance with published indices for gas sold in the San Juan Basin of New Mexico. BROG entered into the contract with El Paso after soliciting and receiving competitive bids in late 1997 from six major gas marketing firms to market and/or purchase the Trust gas. BROG has entered into a contract dated November 10, 1999 for the sale of all volumes of Trust gas to Duke Energy and Marketing L.L.C. ("Duke"). That contract provides for delivery of gas at various delivery points over a 4 6 period commencing January 1, 2000 and ending October 31, 2001 and provides for 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. BROG is negotiating with Duke with respect to the potential for extending the term of that contract. 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. See Note 5 of Notes to Financial Statements of the Trust's Annual Report to securityholders for the year ended December 31, 2000 for further discussion of this settlement and its impact on the Trust. 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: "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, 1998, 1999 and 2000 were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 1997 to December 31, 2000 (in thousands):
CRUDE NATURAL OIL GAS (Bbls) (Mcf) -------- -------- Reserves as of December 31, 1997 ................. 559 203,339 -------- -------- Revisions of previous estimates .................. (195) (26,204) Extensions, discoveries and other additions ...... 6 5,201 Production ....................................... (37) (18,905) -------- -------- Reserves as of December 31, 1998 ................. 333 163,431 -------- -------- Revisions of previous estimates .................. 120 53,936 Extensions, discoveries and other additions ...... 29 14,498 Production ....................................... (32) (17,650) -------- -------- Reserves as of December 31, 1999 ................. 450 214,215 -------- -------- Revisions of previous estimates .................. 199 72,803 Extensions, discoveries and other additions ...... 80 36,207 Production ....................................... (47) (20,318) -------- -------- Reserves as of December 31, 2000 ................. 682 302,907 ======== ========
5 7 Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 2000, 1999 and 1998 were as follows (in thousands):
CRUDE NATURAL OIL GAS (Bbls) (Mcf) ------- ------- 2000 ....................................................................... 624 277,459 1999........................................................................ 422 201,891 1998 ....................................................................... 328 159,454
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 2000, 1999 and 1998 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):
2000 1999 1998 -------- -------- -------- Balance, January 1 ............................................ $229,721 $144,472 $213,504 Revisions of prior-year estimates, change in prices and other .................................................. 530,811 90,172 (63,731) Extensions, discoveries and other additions ................... 94,753 13,257 3,667 Accretion of discount ......................................... 22,972 14,447 21,350 Royalty income ................................................ (60,045) (32,627) (30,318) -------- -------- Balance, December 31 .......................................... $818,212 $229,721 $144,472 ======== ======== ========
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. 6 8 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 upward revision is primarily due to significantly higher gas prices in December 2000. December average prices of $2.39 per Mcf of conventional gas, $1.49 per Mcf of coal seam gas and $22.30 per Bbl of oil were used at December 31, 1999, in determining future net revenue. The upward revision is primarily due to significantly higher gas prices in December 1999. December average prices of $1.82 per Mcf of conventional gas, $1.30 per Mcf of coal seam gas and $8.60 per Bbl of oil were used at December 31, 1998, in determining future net revenue. The downward revision is primarily due to significantly lower oil and gas prices in December 1998 as compared to December 1997. 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, 2000, 1999 and 1998 (in thousands except amounts per Unit):
2000 1999 1998 ------------------------- -------------------------- ------------------------ 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 .............. $1,580,837 $ 818,212 $ 408,609 $ 229,721 $ 241,206 $ 144,472 Proved Developed .......... $1,445,557 $ 752,825 $ 383,356 $ 219,677 $ 234,973 $ 142,095 Total Proved Per Unit ..... $ 33.92 $ 17.55 $ 8.77 $ 4.93 $ 5.18 $ 3.10
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 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 the FERC. The Natural Gas Wellhead Decontrol Act of 1989 ("Decontrol Act") terminated federal price controls on wellhead sales of domestic natural gas on January 1, 1993. Consequently, sales of natural gas may be made at market prices, subject to applicable contract provisions. The FERC's jurisdiction over natural gas transportation and storage was unaffected by the Decontrol Act. 7 9 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. Additional 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 pursued over the last decade 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. Effective as of January 1, 1995, the FERC implemented regulations establishing an indexing system for transportation rates for oil that could increase the cost of transporting oil to the purchaser or reduce wellhead prices for crude oil. 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. For 2000, this tax credit is estimated to be approximately $1.06 per MMBtu, the actual amount to be determined by the Treasury Department no later than April 1, 2001. 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 coal seam volumes produced from Trust 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 the FERC. The FERC's certification authority expired effective January 1, 1993. However, on July 14, 2000, the 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. 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. 8 10 ITEM 3. LEGAL PROCEEDINGS On September 4, 1996, the Trustee announced the settlement of the Litigation filed by the Trustee against BROG and Southland Royalty Company. The Litigation, which was filed in the state district court of Santa Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996. The claims asserted on behalf of the Trust in the Litigation included breach of contract, breach of the covenant of good faith and fair dealing, breach of express good faith duty, constructive fraud, unjust enrichment, prima facie tort, intentional interference with contract and conspiracy. The relief sought included compensatory and punitive damages, an accounting and an injunction relating to marketing the production from the Underlying Properties. BROG has denied and continues to deny the allegations made against it in the Litigation, but the parties have agreed to settle the Litigation as outlined herein. BROG agreed (i) to pay $19,750,000 in cash plus interest earnings thereon from September 5, 1996, in settlement of underpayment of royalty claims of the Trust; and (ii) commencing in 1997, to credit the Trust with $250,000 per year for five years as an offset against lease operating expenses chargeable to the Trust for purposes of the calculation of net proceeds payable to the Trust. BROG also agreed to make certain adjustments that represent cost reductions favorable to the Trust in the ongoing charges for coal seam gas gathering and treating on BROG's Val Verde system. Additionally, the Trustee and BROG established a formal protocol intended to provide the Trustee and its representatives improved access to BROG's books and records applicable to the Underlying Properties. Agreement was also reached regarding marketing arrangements for the sale of Trust gas, oil and natural gas liquids products going forward as more particularly described in "Pricing Information" under Item 2. Properties herein. The $19,822,005 (or $.425285 per unit of beneficial interest) was paid to the Trust on September 30, 1996 and distributed on October 15, 1996, to unitholders of record as of September 30, 1996, (the "Record Date"). The distribution was taxable to unit holders as of such Record Date. This distribution was in addition to the regular monthly distribution on October 15, 1996. A lawsuit was commenced on September 1, 1995 against BROG by certain royalty and overriding royalty owners on behalf of those persons similarly situated. This case is one of six virtually identical class actions filed against New Mexico gas producers. All such cases have been consolidated in the First Judicial District of Santa Fe County, New Mexico where the case is styled San Juan 1990-A, L.P., et al. v. El Paso Production Co., et al. The plaintiffs allege that they and members of the proposed class have been underpaid for royalties and overriding royalties. BROG has now informed the Trust that this litigation is unlikely to have any direct effect on royalty income payable to the Trust. In addition, 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 alleges that additional royalties are due on production from federal and Indian leases in the State of New Mexico on properties that are burdened by the Royalty. BROG filed its statement of reasons in June 1997 thereby contesting whether the royalties are payable as claimed. BROG has informed the Trust that the administrative claim is in the appeal process. If the MMS claim is successful, royalty income received by the Trust could decrease. BROG reports that the MMS and BROG have entered into settlement discussions in an attempt to settle this issue together with other take-or-pay claims made by the MMS, but there has been no indication of the likelihood of success in resolving the claim or when the negotiations are to be completed. MMS has notified BROG of underpaid royalty related to coal seam gas including inappropriate deductions for costs to separate carbon dioxide from the gas. BROG has continued to calculate and pay royalties using deductions the MMS is attempting to disallow. The Company has appealed the MMS Demand Letter dated October 28, 1996. There is a tolling agreement with the MMS while settlement negotiations are attempted. 9 11 An administrative claim was initiated on June 10, 1998 by the MMS against BROG related to production from lands on the Jicarilla Apache Indian Reservation. The claim alleges that additional royalties are due based upon the "major portion" valuation clause contained in the Jicarilla leases. This clause contemplates royalty value to be calculated on "the highest price paid or offered at the time of production for the major portion of oil of the same gravity, and gas, and/or natural gasoline, and/or all other hydrocarbon substances produced and sold from the field where the leased lands are situated." BROG indicates that producers do not have access to prices received by other producers in a field, so a "major portion" calculation must be done by the MMS. BROG filed its statement of reasons in June 1999 thereby contesting whether the royalties are payable as claimed. The administrative claim is in the appeal process. If the MMS claim is successful, royalty income received by the Trust could decrease. BROG has successfully negotiated with the State of New Mexico for a tax refund based upon a claim for reimbursement of compression costs used in calculating wellhead values. BROG has obtained the approval of the Attorney General of New Mexico of a settlement in the amount of $4,200,000, and in December 2000 passed through to the Trust $263,607 of the settlement proceeds in the form of a reduction in production costs. The Trust's consultants are in communication with BROG and will review the allocation of settlement proceeds. 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 subject properties. The remainder of the imbalance is to be addressed through volume adjustments whereby the Trust's net overriding royalty interest will be applied to 50% of the overproduced parties' interest, on a monthly basis, until the imbalance is corrected. The Trust is 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. Those adjustments will be monitored by the Trust's consultants. For additional information concerning legal proceedings, Note 5 of the Notes to Financial Statements at pages 14 and 15 of the Trust's Annual Report to security holders for the year ended December 31, 2000 are herein incorporated by reference. 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, 2000. 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, 2000, is herein incorporated by reference. 10 12 ITEM 6. SELECTED FINANCIAL DATA
For the Year Ended December 31, --------------------------------------------------------------------------- 2000 1999 1998 1997 1996 ----------- ----------- ----------- ----------- ----------- Royalty income ............... $60,044,773 $32,626,966 $30,317,860 $49,497,479 $41,236,424(1) Distributable income ......... 59,188,932 31,795,667 29,598,402 48,648,930 37,803,167 Distributable income per Unit ...................... 1.269909 0.682182 0.635039 1.043770 0.811072 Distributions per Unit ....... 1.269909 0.682182 0.635039 1.043770 0.811072 Total assets, December 31 .... 47,659,746 49,048,652 53,753,582 61,231,280 65,935,976
---------- (1) The royalty income distributions for 1996 include material payments received in settlement of litigation as more particularly described under "Item 2. Properties" herein. ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION The "Trustee's Discussion and Analysis" and "Results of the 4th Quarters of 2000 and 1999" at pages 7 through 9 of the Trust's Annual Report to securityholders for the year ended December 31, 2000, are herein incorporated by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Trust has not entered into derivative financial instruments, derivative commodity instruments or other similar instruments during 2000. As discussed in Item 2. Properties -- Pricing Information, 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, 2000, are herein incorporated by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 11 13 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 or executive officers. During the year ended December 31, 2000, the Trustee received total remuneration as follows:
NAME OF INDIVIDUAL OR NUMBER OF CAPACITIES IN WHICH CASH PERSONS IN GROUP SERVED COMPENSATION -------------------------------- ------------------- ------------ Bank One, NA.......................................................... Trustee $ 98,512.40(1)
---------- (1) Under the Trust Indenture, the Trustee is entitled to an administrative fee for its administrative services, preparation of quarterly and annual statements with attention to tax and legal matters of: (i) 1/20 of 1% of the first $100 million 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. The administrative fee is subject to reduction by a credit for funds provision. ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security Ownership of Certain Beneficial Owners. The following table sets forth, as of December 31, 2000, 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) ............................. 15,594,000 Units 33.5% 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 Arnhold and S. Bleichroeder, Inc.(3) ............... 2,988,300 Units 6.4% Arnhold and S. Bleichroeder Advisers, Inc. 1345 Avenue of the Americas New York, New York 10105 McMorgan and Company(4) ............................ 3,000,000 Units 6.4% 1 Bush Street, Suite 800 San Francisco, CA 94104 Capital Group International, Inc.(5) ............... 2,635,200 Units 5.7% Capital Guardian Trust Company 11100 Santa Monica Blvd Los Angeles, CA 90025
---------- (1) This information was provided to the Trust on Amendment Number 19 to Schedule 13D, dated April 14, 2000, as filed with the Securities and Exchange Commission (the "SEC") by Alpine Capital L.P. ("Alpine"), which indicated that these Units were beneficially owned by Alpine. The Amendment Number 19 to Schedule 13D may be reviewed for more detailed information concerning the matters summarized herein. 12 14 (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 4 to Schedule 13G, dated February 13, 2001. Arnhold and S. Bleichroeder, Inc. and Arnhold and S. Bleichroeder Advisers, Inc. report shared voting power over 2,988,300 Units and shared dispositive power over 2,988,300 Units. The Amendment Number 4 to Schedule 13G filed with the SEC 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. (5) This information was provided to the Trust in Amendment Number 3 to Schedule 13G dated December 29, 2000. Capital Group International, Inc. and Capital Guardian Trust Company each reported sole voting power over 1,977,800 Units and sole dispositive power over 2,635,200 Units. The Amendment Number 3 to Schedule 13G may be reviewed for more detailed information concerning the matters summarized herein. (b) Security Ownership of Management. In various fiduciary capacities, Bank One, NA owned, as of December 31, 2000, an aggregate of 32,652 Units with no right to vote any of these Units. Bank One, NA disclaims any beneficial interest in these Units. The number of Units reflected in this paragraph includes Units held by all branches of Bank One, NA. 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, 2000 and Item 12(b) for information concerning Units owned by Bank One, NA in various fiduciary capacities. 13 15 PART IV ITEM 14. 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, 2000: Independent Auditors' Report 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.
EXHIBIT NUMBER DESCRIPTION ------ ----------- (4)(a) -- San Juan Basin Royalty Trust Indenture, dated November 3, 1980, between Southland Royalty Company and The Fort Worth National Bank (now Bank One, NA), as Trustee, heretofore filed as Exhibit 4(a) to the Trust's Annual Report on Form 10-K to the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (b) -- Net Overriding Royalty Conveyance from Southland Royalty Company to the Forth Worth National Bank (now Bank One, NA), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K to the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (13) -- Registrant's Annual Report to security holders for fiscal year ended December 31, 2000.** (23) -- Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
---------- * A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon written request to the Trustee, Bank One, NA, P.O. Box 2604, Fort Worth, Texas 76113. ** Filed herewith. REPORTS ON FORM 8-K On October 27, 2000, a report on Form 8-K was filed with the Securities and Exchange Commission by the Trust, announcing the upward adjustment of anticipated capital expenses of the Trust for fiscal year ended December 31, 2000. 14 16 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. BANK ONE, NA TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST By:/s/ LEE ANN ANDERSON -------------------------------------- (Lee Ann Anderson) Vice President Date: March 30, 2001 (The Trust has no directors or executive officers) 15 17 EXHIBIT INDEX
EXHIBIT NUMBER DESCRIPTION ------ ----------- (4)(a) -- San Juan Basin Royalty Trust Indenture, dated November 3, 1980, between Southland Royalty Company and The Fort Worth National Bank (now Bank One, NA), as Trustee, heretofore filed as Exhibit 4(a) to the Trust's Annual Report on Form 10-K to the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (b) -- Net Overriding Royalty Conveyance from Southland Royalty Company to the Forth Worth National Bank (now Bank One, NA), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K to the SEC for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (13) -- Registrant's Annual Report to security holders for fiscal year ended December 31, 2000.** (23) -- Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.**
---------- * A copy of this Exhibit is available to any Unit holder, at the actual cost of reproduction, upon written request to the Trustee, Bank One, NA, P.O. Box 2604, Fort Worth, Texas 76113. ** Filed herewith. 16