-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, JvjzfZ3FnZlm+o9L9AWSX4cGOIhTaZpXZXRVfmmLkq3anrcJsDX+g9pAnE8Tsuwq 7W2CXMMB9D6fmvMgWLpG0Q== 0000930661-98-000709.txt : 19980401 0000930661-98-000709.hdr.sgml : 19980401 ACCESSION NUMBER: 0000930661-98-000709 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19971231 FILED AS OF DATE: 19980331 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: SAN JUAN BASIN ROYALTY TRUST CENTRAL INDEX KEY: 0000319655 STANDARD INDUSTRIAL CLASSIFICATION: OIL ROYALTY TRADERS [6792] IRS NUMBER: 756279898 STATE OF INCORPORATION: TX FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-K405 SEC ACT: SEC FILE NUMBER: 001-08032 FILM NUMBER: 98582431 BUSINESS ADDRESS: STREET 1: BANK ONE TEXAS N A TRUST CITY: FT WORTH STATE: TX ZIP: 76113 BUSINESS PHONE: 8178844630 MAIL ADDRESS: STREET 1: 1600 BANK ONE TOWER STREET 2: 500 THROCKMORTON CITY: FORT WORTH STATE: TX ZIP: 76102-3899 10-K405 1 FORM 10-K - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- 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, 1997, 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, TEXAS, N.A. 76113 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: 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. [X] At March 25, 1998, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding with an aggregate market value on that date of $372,870,368. DOCUMENTS INCORPORATED BY REFERENCE "Units of Beneficial Interest" at page 2; "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 1997 and 1996" 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 security holders for fiscal year ended December 31, 1997 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. - ------------------------------------------------------------------------------- - ------------------------------------------------------------------------------- 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, Texas, N.A. 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 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 1 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 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 recovered 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. As the year 2000 approaches, there are uncertainties concerning whether computer systems will properly recognize date-sensitive information when the year changes to 2000. Systems that do not properly recognize such information could generate erroneous data or fail. The Trust is in communication with third parties with which it deals, but it is not yet possible to fully assess the effect of a third party's inability to adequately address year 2000 issues. 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 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 the Trustee by BROG. 2 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. Based upon information received from the Trust's independent petroleum engineers, the Trust properties contain 3,038 gross (909 net) economic wells, including dual completions. Production from conventional gas wells is primarily from the Pictured Cliffs, Mesa Verde and Dakota formations. During 1988, Southland Royalty began development of coal seam reserves in the Fruitland 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, 1997, 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 1997, BROG incurred approximately $7.2 million of capital expenditures for the drilling and completion of 64 gross (3.53 net) conventional wells, recompletion of 14 gross (5.4 net) conventional wells, drilling and completion of 1 gross (.84 net) coal seam well, and 21 gross (2.32 net) coal seam recavitations. There were 5 (1.22 net) new conventional wells, 3 (1.08 net) conventional recompletions, 11 gross (.42 net) coal seam recompletions, 5 (.20 net) coal seam recavitations, and 1 (.04 net) coal seam well in progress as of December 31, 1997. During 1996, there were 14 gross (1.50 net) conventional wells completed. There was 1 gross (.05 net) coal seam well and 17 gross (1.96 net) conventional wells in progress at December 31, 1996. There were 4 gross (.16 net) conventional wells recompleted as coal seam wells, 17 gross (5.63 net) coal seam wells recavitated and 9 gross (5.93 net) conventional wells recompleted through December 31, 1996. 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, 1997 were as follows:
1997 1996 1995 ------------------- ------------------- ------------------- OIL GAS OIL GAS OIL GAS (BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF) ------- ----------- ------- ----------- ------- ----------- Production......... 50,860 24,236,419 36,792 17,927,785 29,424 13,331,758 Average Price...... $ 19.35 $ 2.21 $ 19.64 $ 1.30 $ 14.43 $ 1.25
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 41,948,567 Mcf during 1997. Prior to 1985, sales contracts with El Paso, Sunterra Gas Gathering Company, formerly Southern Union Gathering Company ("Sunterra"), and Northwest Pipeline Company ("Northwest") generally provided for payment of the maximum lawful prices permitted under the Natural Gas Policy Act of 1978 ("NGPA"). Sunterra is a subsidiary of Public Service Company of New Mexico ("PNM"). In 1985, Sunterra sold its gas gathering, transportation and distribution facilities in New Mexico and its rights as purchaser under its San Juan Basin gas contracts to PNM. Under such contracts, gas prices were to be redetermined annually on April 1 to an average of the highest price levels being paid in New Mexico. Also in 1985, PNM announced its intention to attempt to renegotiate the gas contracts with gas producers in the San Juan Basin, including Southland Royalty, with its objective being to reduce the overall price for such gas. During the course of these negotiations PNM unilaterally reduced the price paid for gas sales below the level required by the gas contracts. 3 In May 1988, PNM filed suit in the United States District Court in New Mexico seeking (i) a declaratory judgment that PNM had no prior liability for gas purchased at prices below the contract prices and (ii) a permanent injunction prohibiting future claims against PNM for gas purchases at prices below the contract prices. PNM claimed the pricing provisions were the result of a conspiracy in violation of antitrust laws. Southland Royalty counter- claimed against PNM alleging breach of both the pricing provisions and the minimum take requirements of the gas purchase contracts. In June 1988, Southland Royalty filed a separate breach of contract suit in a State District Court in Harris County, Texas on these same claims against PNM alleging damages in excess of $40 million. During 1988, both El Paso and Northwest abandoned the Natural Gas Act ("NGA") service obligation to purchase gas in accordance with Federal Energy Regulatory Commission ("FERC") Order 490 and 490-A. Southland Royalty informed the Trust that effective March 1, 1990 a settlement of this litigation was reached. Under the terms of the settlement agreement, Southland Royalty released all claims that it had against PNM, Sunterra and Gas Company of New Mexico (a division of PNM) ("Gas Company")under the intrastate gas purchase contracts, as well as claims it held on gas sold pursuant to the interstate contracts discussed previously. PNM and Sunterra agreed to pay Southland Royalty $54.5 million in installments. An initial payment of $18,166,000 was paid in connection with the execution of the settlement agreement. The second payment of $18,167,000 was paid on March 1, 1991. The remaining balance of $18,167,000 was paid on March 2, 1992 plus interest of $1,635,300. Southland Royalty distributed to the Trust 75% (the amount of its net overriding royalty interest) of the $49,435,300 in cash received in settlement that it attributed to past and future pricing claims under the intrastate and interstate gas purchase contracts, less amounts attributed by Southland Royalty to royalties and production taxes. Southland Royalty retained a total of $6,700,000 from the settlement proceeds that it attributed to quantity claims. Because of the difficulty in determining the exact value of consideration received under the renegotiated contracts referred to below, Southland Royalty informed the Trust that it would not attribute value to quantity claims under the renegotiated contracts and the Trust would receive 75% (the amount of its net overriding royalty interest) of any value that ultimately inured to those contracts. Southland Royalty also informed the Trust that the settlement also provided for new gas purchase agreements replacing the then current intrastate and interstate gas purchase agreements. Southland Royalty entered into five-year gas purchase, gas processing and gas gathering agreements with Sunterra and gas Company that were effective as of July 1, 1990. The new contracts applied to all lands previously dedicated to Sunterra and Gas Company for first sales of natural gas sold into interstate or intrastate markets, except that the new gas purchase contracts exclude all gas produced and sold from coal seam wells. The new gas purchase contracts provided for purchase rights and obligations during the winter heating season only. During the remainder of the year, Southland Royalty through MOTI could market the gas through any arrangements it deemed advisable. Under the new gas contracts, Southland Royalty would receive prices, inclusive of severance taxes, ranging from approximately $2.35 per month MMBtu to $3.37 per MMBtu over the life of the contracts. The contracts provided for certain "take-or-pay obligations" if specified quantities of gas (66% of the maximum volume that can be produced into the gathering system against the Assumed Working Pressure of a purchase period and lawfully made available for sale to the gas purchaser each day during a purchase period) are not taken by the purchasers during the winter heating season. Should the required minimum not be taken, then a reservation fee was to be paid to Southland Royalty to be determined by multiplying 20% of the price of gas for the applicable time period times the deficiency for the purchase period. See Note 5 of Notes to Financial Statements of the Trust's Annual Report to security holders for the year ended December 31, 1997 for further discussion of this settlement and its impact upon the Trust. The gas gathering contract provided for transportation of gas not taken by Sunterra and Gas Company during the winter heating season and during the remainder of the year. The gas processing agreement provided that Southland Royalty received 80% of the plant products derived from processing the gas. The processing company was to retain the remaining 20% as its fee for processing the gas. 4 In 1991, due to the low level of natural gas prices, Sunterra informed Southland Royalty that it would not take any significant volume of gas during the 1991-1992 winter heating season and would simply pay the "take or pay obligation" amount. Consequently, the majority of the wells subject to the contracts would remain shut-in during the winter heating season. Southland Royalty informed the Trustee that, in an attempt to maximize production and revenue from the Trust properties, it had entered into an agreement that would amend the terms of the contracts discussed above for only the 1991-1992 winter heating season. The amendment provided that Sunterra and gas Company could purchase approximately 35% of the contract provided take levels at a wellhead price slightly higher than the spot wellhead index price for the San Juan Basin. Any gas purchased by Sunterra or Gas Company above this level would average $2.63 per MMBtu. Southland Royalty would be free to market the remaining deliverable gas to other purchasers. During 1992 Gas Company and Sunterra purchased 702,629 Mcf and 3,241,500 Mcf, respectively, at average prices of $2.25 and $1.98 per Mcf, respectively, from the properties from which the Royalty was carved. Southland Royalty informed the Trust that a one year contract amendment was agreed to with Gas Company and Sunterra for the 1992-1993 winter heating season. Gas Company and Sunterra were required to purchase a minimum of 11,500 MMBtu per day under the intrastate contract and a minimum of 16,550 MMBtu per day under the interstate contracts at the contract specified prices of $2.695 per MMBtu and $2.94 per MMBtu, respectively. A portion of the excess gas up to 9,000 MMBtu per day for the intrastate contracts and 12,000 MMBtu per day for the interstate contracts was released for spot sales, with a recall provision at an average contract price. Southland Royalty waived any claims for deficiency payments under the reservation fees. Southland Royalty informed the Trust that a similar amendment was entered into for the 1993-1994 winter heating season. Gas Company and Sunterra were required to purchase a minimum of 1,696,485 MMBtu with an average minimum of 5,100 MMBtu per day under the intrastate contracts between November 1, 1993 and March 1994 and a minimum of 1,401,570 MMBtu with an average minimum of 7,000 MMBtu per day under the interstate contract between December 1, 1993 and February 28, 1994 at the contract specified prices of $2.884 per MMBtu and$3.146 per MMBtu, respectively. All remaining intrastate gas in excess of 11,300 MMBtu per day during the period November 1, 1993 and through March 31,1994 and all remaining interstate gas in excess of 15,600 MMBtu per day during the period December 1, 1993 through February 28, 1994 was released for spot sales, with a recall provision at a price during the months of November 1993 and March 1994 of $2.884 per MMBtu and $3.015 per MMBtu for the months December 1993, January 1994, and February 1994. Southland Royalty informed the Trust that an amendment was also entered into for the 1994-1995 winter heating season. Gas Company and Sunterra were required to purchase, at the wellhead, an average volume of 10,529 MMBtu per day at $2.884 per MMBtu for the period beginning November 1, 1994 and ended March 31, 1995 and an additional 14,900 MMBtu per day at $3.146 per MMBtu for the period beginning December 1, 1994 and ended February 28, 1995. Gas Company and Sunterra were granted a make-up period of four months beginning April 1,1995 to fulfill this purchase obligation. Gas Company and Sunterra were also granted recall rights on volumes up to 15,000 MMBtu per day at the tailgate of the Kutz and Lybrook plants, provided they nominated the full contract volume specified above. The price for recall was to be the average of the first and second issues of the Inside FERC EPNG SJ Index. The Trust was informed that effective July 1, 1995, Williams Field Services ("Williams") purchased the Kutz and Lybrook processing plants and the gathering systems behind these plants which were owned by Sunterra, Gas Company and Sunterra Gas Processing Company ("SGPC") and that new gathering and processing agreements with Williams were entered into which contain acceptable rates, terms and conditions. The new agreements replaced the then current gathering and processing agreements with Gas Company, Sunterra and SGPC effective on the closing date of the sale of these facilities to Williams. 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. 5 Agreement was reached, among other things, regarding marketing arrangements for the sale of Trust gas, oil and natural gas liquids products going forward as follows: (i) BROG's pre-existing contract with a third-party purchaser covering baseload gas volumes in the firm amount of 45,000 MMBtus/day was to remain effective for a period of one year from July 1, 1996. The remaining volumes of Trust gas were marketed by an independent marketer, El Paso Energy Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation, beginning October 1, 1996. BROG agreed that 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 remit to the Trust 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 Trust has retained access to BROG's current gas transportation, gathering, processing and treating agreements with third parties through the remainder or their primary terms. Additionally, El Paso could utilize BROG's eastern transportation agreement for delivery from the San Juan Basin on the El Paso Natural Gas Company pipeline to pipelines in West Texas of up to 13,333 MMBtu's/day of gas produced from Trust properties for a period of one year commencing October 1, 1996. 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 is for a term of two years through and including December 31, 1999 and provides 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. While it is impossible to predict the exact economic value of gas contracts, the Trust has been advised by its independent gas marketing consultant that the contract with El Paso should provide for the average highest sales price for natural gas in the San Juan Basin over the two-year term of the contract. See Note 5 of Notes to Financial Statements of the Trust's Annual Report to securityholders for the year ended December 31, 1997 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: "Proved reserves" are those estimated quantities of crude oil, natural gas and natural gas liquids, which, upon analysis of geological and engineering data, appear with reasonable certainty to be recoverable in the future from known oil and gas reservoirs under existing economic and operating conditions. "Proved developed reserves" are those proved reserves which can be expected to be recovered through existing wells with existing equipment and operating methods. "Proved undeveloped reserves" are those proved reserves which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required. "Estimated future net revenues" are computed by applying current prices of oil and gas (with consideration of price changes only to the extent provided by contractual arrangements and allowed by federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. "Estimated future net revenues" are sometimes referred to herein as "estimated future net cash flows." 6 "Present value of estimated future net revenues" is computed using the estimated future net revenues and a discount rate of 10%. The independent petroleum engineers' reports as to the proved oil and gas reserves as of December 31, 1995, 1996 and 1997 were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 1994 to December 31, 1997 (in thousands):
NATURAL OIL GAS (BBLS) (MCF) ------ ------- Reserves as of December 31, 1994............................. 612 201,405 Revisions of previous estimates.............................. (165) (22,529) Extensions, discoveries and other additions.................. 0 906 Production................................................... (29) (13,332) ---- ------- Reserves as of December 31, 1995............................. 418 166,450 Revisions of previous estimates.............................. 272 95,106 Extensions, discoveries and other additions.................. 4 2,367 Production................................................... (37) (17,928) ---- ------- Reserves as of December 31, 1996 657 245,995 ---- ------- Revisions of previous estimates.............................. (81) (25,734) Extensions, discoveries and other additions.................. 34 7,314 Production................................................... (51) (24,236) Reserves as of December 31, 1997............................. 559 203,339 ==== ======= Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 1997, 1996 and 1995 were as follows (in thousands): CRUDE NATURAL OIL GAS (BBLS) (MCF) ------ ------- 1997......................................................... 547 199,753 1996......................................................... 637 239,962 1995......................................................... 418 159,650
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. 7 The 1997, 1996 and 1995 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):
1997 1996 1995 --------- -------- -------- Balance, January 1........................... $ 439,037 $106,937 $157,627 Revisions of prior-year estimates, change in prices and other................................... (227,855) 338,208 (51,819) Extensions, discoveries and other additions.. 7,915 4,612 522 Accretion of discount........................ 43,904 10,694 15,763 Royalty income............................... (49,497) (21,414) (15,156) --------- -------- -------- Balance, December 31......................... $ 213,504 $439,037 $106,937 ========= ======== ========
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 $2.21 per Mcf of conventional gas, $1.55 per Mcf of coal seam gas and $15.97 per Bbl of oil were used at December 31, 1997, in determining future net revenue. The downward revision is primarily due to significantly lower gas prices in December 1997 as compared to December 1996. December average prices of $4.04 per Mcf of conventional gas, $2.84 per Mcf of coal seam gas and $23.18 per Bbl of oil were used at December 31, 1996, in determining future net revenue. The upward revision is primarily due to significantly higher gas prices in December 1996. December average prices of $1.36 per Mcf of conventional gas, $0.85 per Mcf of coal seam gas and $17.24 per Bbl of oil were used at December 31, 1995, 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, 1997, 1996 and 1995 (in thousands except amounts per Unit):
1997 1996 1995 ------------------ ------------------ ------------------ 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............ $372,830 $213,504 $822,131 $439,037 $184,055 $106,937 Proved Developed........ $365,509 $211,580 $799,664 $430,365 $175,824 $104,378 Total Proved Per Unit... $ 8.00 $ 4.58 $ 17.64 $ 9.42 $ 3.95 $ 2.29
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. 8 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 or 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 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. Sales of natural gas are affected by the availability, terms and cost of transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. Several major regulatory changes have been implemented by Congress and the FERC from 1985 to the present that affect the economics of natural gas production, transportation, and sales. In addition, the FERC continues to promulgate revisions to various aspects of the rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to the FERC's jurisdiction. These initiatives may also affect the intrastate transportation of gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation of the natural gas industry. The ultimate impact of the rules and regulations issued by the FERC since 1985 cannot be predicted. In addition, many aspects of these regulatory developments have not become final but are still pending judicial and FERC final decisions. 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 recently pursued by the FERC and Congress will continue. Sales of crude oil, condensate and gas liquids are not currently regulated and are made at market prices. 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. The Trust is not able to predict what effect, if any, these regulations will have on it, but other factors being equal, the regulations may tend to increase transportation costs or reduce wellhead prices for crude oil. Coal Seam Tax Credit The Trust began receiving royalty income from coal seam wells beginning in 1989. Under Section 29 of the Internal Revenue Code, production from coal seam gas wells drilled prior to January 1, 1993, qualifies for the federal income tax credit for producing non-conventional fuels. Production from wells drilled after December 31, 1979 but prior to January 1, 1993, to a formation beneath qualifying coal seam formation which are later completed into such formation also qualifies for the tax credit. This tax credit for 1997 was approximately $1.05 per MMBtu and applies to production through the year 2002. Each Unitholder must determine his pro rata share 9 of such production based upon the number of Units owned during each month of the year and apply the tax credit against his own income tax liability, but such credit may not reduce his regular 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. Other Regulation The oil and natural gas industry is also subject to compliance with various other federal, state and local regulations and laws, including, but not limited to, environmental protection, occupational safety, resource conservation and equal employment opportunity. ITEM 3. LEGAL PROCEEDINGS 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. 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 $19,750,000 (or $.423739 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 is taxable to unit holders as of such Record Date. This distribution was in addition to the regular monthly distribution on October 15, 1996. For additional information concerning legal proceedings, Note 5 of the Notes to Financial Statements at pages 13 and 14 of the Trust's Annual Report to security holders for the year ended December 31, 1997 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, 1997. 10 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 31,1997, is herein incorporated by reference. ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31, ---------------------------------------------------------------- 1997 1996 1995 1994 1993 ------------ ------------ ------------ ------------ ------------ Royalty income(1)....... $ 49,497,479 $ 41,236,424 $ 15,156,292 $ 23,280,188 $ 37,576,121 Distributable income.... 48,648,930 37,803,167 13,790,101 22,632,493 36,760,797 Distributable income per Unit.................... 1.043770 0.811072 0.295867 0.485584 0.788710 Distributions per Unit.. 1.043770 0.811072 0.295867 0.485584 0.788710 Total assets, December 31...................... 61,231,280 65,935,976 70,554,982 75,531,405 82,701,203
- -------- (1) The royalty income distributions for 1993 and 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 1997 and 1996" at pages 7 through 9 of the Trust's Annual Report to securityholders for the year ended December 31, 1997, are herein incorporated by reference. ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK Not applicable ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The Financial Statements of the Trust and the and the notes thereto at page 10 et seq., of the Trust's Annual Report to security holders for the year ended December 31, 1997, are herein incorporated by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 11 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 Unitholders, by the affirmative vote of the holders of a majority of all the Units then outstanding. ITEM 11. EXECUTIVE COMPENSATION During the year ended December 31, 1997, the Trustee received total remuneration as follows:
NAME OF INDIVIDUAL OR NUMBER OF CAPACITIES IN WHICH CASH PERSONS IN GROUP SERVED COMPENSATION ------------------------------- ------------------- ------------ Bank One, Texas, N.A..................... Trustee $132,880(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, 1997, 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 ---------------- -------------------- ---------------- Fund American Enterprises Holdings, Inc.(1) ............... 5,994,876 Units 14.4% 80 South Main Street Hanover, New Hampshire 03755 Capital Guardian Trust Company (2).............................. 4,078,800 Units 8.8% 333 South Hope Street, 52nd Floor Los Angeles, California 90071
- -------- (1) This information was provided to the Trust on Form 4, dated December 3, 1997, as filed with the Securities and Exchange Commission (the "SEC") by Fund American Enterprises Holdings, Inc.("FAEH"), which indicated that these Units were owned by Fund American Enterprises, Inc. The Form 4 and an Amendment Number 8 to Schedule 13D, dated December 2, 1997 filed by FAEH with the SEC may be reviewed for more detailed information concerning the matters summarized herein. (2) This information was provided to the SEC and to the Trust in Amendment Number 4 to Schedule 13G, dated February 10, 1998, filed jointly by The Capital Group Companies, Inc. ("Capital Group") and Capital Guardian Trust Company ("Capital Guardian"). Capital Guardian is a wholly-owned operating subsidiary of Capital Group. Capital Guardian exercised investment discretion with respect to the 4,078,800 Units which were owned by various institutional investors. Capital Group disclaims beneficial ownership of such Units pursuant to Rule 13d-4 of the Securities Exchange Act of 1934. Both Capital Group and Capital Guardian report sole voting power over 3,403,800 Units and sole dispositive power over 4,078,800 Units. The Amendment Number 4 to Schedule 13G filed by Capital Group and Capital Guardian with the SEC may be reviewed for more detailed information concerning the matters summarized herein. III-1 (b) Security Ownership of Management. In various fiduciary capacities, Bank One, Texas, N.A. owned, as of December 31, 1997, an aggregate of 29,272 Units with the sole right to vote 23,672 of these Units and no right to vote 5,600 of these Units. Bank One, Texas, N.A. disclaims any beneficial interest in these Units. The number of Units reflected in this paragraph includes Units held by all branches of Bank One, Texas, N.A. 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, 1997 and Item 12(b) for information concerning Units owned by Bank One, Texas, N.A. in various fiduciary capacities. III-2 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, 1997: Independent Auditors' Report Statement 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.
EXHIBITS (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, Texas, N.A.), 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, Texas, N.A.), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K to the 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, 1997.** (23) --Consent of Cawley, Gillespie & Associates, Inc., reservoir engineer.** (27) --Financial Data Schedule.**
- -------- * 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, Texas, N.A., P.O. Box 2604, Fort Worth, Texas 76113. ** Filed herewith. REPORTS ON FORM 8-K During the last quarter of the Trust fiscal year ended December 31, 1997, no reports on Form 8-K were filed with the Securities and Exchange Commission by the Trust. IV-1 SIGNATURE Pursuant to the Requirements of Section 13 or 15(d) of the Securities and 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, TEXAS, N.A. TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST By: /s/ Lee Ann Anderson _____________________________________ (Lee Ann Anderson) Vice President Date: March 31, 1998 (The Trust has no directors or executive officers) EX-13 2 ANNUAL REPORT EXHIBIT 13 [PHOTO APPEARS HERE] SAN JUAN BASIN ROYALTY TRUST 1997 ANNUAL REPORT & 10K The San Juan Basin Royalty Trust is building a World Wide Web site for the convenience of investors. By mid-May 1998, information about the Trust and its functions will be found at www.sjbrt.com The principal asset of the San Juan Basin Royalty Trust consists of a 75% net overriding royal- ty interest carved out of certain oil and gas leasehold and royalty interests in the San Juan Basin of northwestern New Mexico. THE TRUST UNITS OF BENEFICIAL INTEREST The Units of Beneficial Interest of the Trust ("Units") are traded on the New York Stock Exchange under the symbol "SJT." From January 1, 1996, to December 31, 1997, quarterly high and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows: - -------------------------------------------------------------------------------- Distributions 1995 High Low Paid - ---- -------- ------- ---------- First Quarter__________________________ $ 8.8750 $7.5000 $ 0.391930 Second Quarter_________________________ 8.3125 7.2500 0.183766 Third Quarter__________________________ 10.1250 7.9375 0.206076 Fourth Quarter_________________________ 10.5626 8.6875 0.261998 ---------- Total for 1997______________________ $ 1.043770 ========== 1996 - ---- First Quarter__________________________ $ 6.8750 $5.8750 $ .084239 Second Quarter_________________________ 6.5000 5.6250 .063143 Third Quarter__________________________ 7.5000 6.0000 .488979 Fourth Quarter_________________________ 8.6250 6.1250 .174711 ---------- Total for 1996______________________ $ .811072 ========== - ------------------------------------------------------------------------------- At December 31, 1997, 46,608,796 Units outstanding were held by 2,505 Unit holders of record. The following table presents information relating to the distribution of ownership Units: Number of TYPE OF UNIT HOLDERS Unit Holders Units Held - -------------------- ------------ ---------- Individuals_______________________________________ 2,113 3,520,866 Fiduciaries_______________________________________ 356 1,190,649 Institutions______________________________________ 16 289,777 Brokers, Dealers and Nominees_____________________ 5 39,912,462 Corporations and Partnerships_____________________ 8 1,649,092 Miscellaneous_____________________________________ 7 45,950 ------------ ---------- Total__________________________________________ 2,505 46,608,796 ============ ========== - -------------------------------------------------------------------------------- TO UNIT HOLDERS We are pleased to present the 1997 Annual Report of the San Juan Basin Royalty Trust. The report includes a copy of the Trust's Annual Report on Form 10-K to the Securities and Exchange Commission for the year ended December 31, 1997, without exhibits. Production figures provided in this letter and in the Trustee's Discussion and Analysis are based on information provided by Burlington Resources Oil & Gas Company ("BROG"). The Trust was established in November 1980 by Trust Indenture between Southland Royalty and The Fort Worth National Bank. Pursuant to the Indenture, Southland Royalty conveyed to the Trust a 75% net overriding royalty interest (equivalent to a net profits interest) carved out of Southland Royalty's oil and gas leasehold and royalty interest in the San Juan Basin of northwestern New Mexico. This net overriding royalty interest (the "Royalty") is the principal asset of the Trust. The Form 10-K contains important information concerning, among other things, the oil and gas reserves attributable to the Royalty and the properties from which the Royalty was carved. Under the Trust Indenture, Bank One, Texas, N.A. (successor trustee) as Trustee, has the primary function of collecting monthly net proceeds ("Royalty Income") attributable to the Royalty and making the monthly distributions to the Unit holders after deducting administrative expenses and any amounts necessary for cash reserves. Income to Unit holders for the year 1997 was $48,648,930 or $1.043770 per Unit. This distributable income consisted of Royalty Income of $49,497,479 plus interest income of $99,403, less administrative expenses of $947,952. In September 1988, the Trust was advised by Southland Royalty and its affiliate Meridian Oil, Inc. ("MOI"), both of which were subsidiaries of Burlington Resources, Inc., that they had initiated a drilling program in the San Juan Basin of northwestern New Mexico involving development of Fruitland Coal Seam gas reserves on properties in which the Trust owns an interest. For more information on the coal seam drilling program and the related Federal income tax credit associated with gas produced from coal seam wells drilled before January 1, 1993, please see the "Description of the Properties" section of this Annual Report. On January 2, 1996, Southland Royalty was merged with and became a wholly- owned subsidiary of MOI. Subsequent to the merger, MOI changed its name to Burlington Resources Oil & Gas Company. Information about the Trust's estimated proved reserves of gas, including coal seam gas, and of oil as well as the present value of net revenues discounted at 10% can be found in Item 2 of the accompanying Form 10-K. Royalty Income is generally considered portfolio income under the passive loss rules enacted by the Tax Reform Act of 1986. Therefore, it appears that Unit holders should not consider the taxable income from the Trust to be passive income in determining net passive income or loss. Unit holders should consult their tax advisors for further information. Unit holders of record will continue to receive an individualized tax information letter for each of the quarters ending March 31, June 30 and September 30, 1998, and for the year ending December 31, 1998. Unit holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request. We are pleased to announce that the new Web site for the Trust will be accessible in mid-May 1998. Please visit the site at www.sjbrt.com to access our news releases, reports, SEC filings and tax information. Bank One, Texas, NA., Trustee By: /s/ LEE ANN ANDERSON Lee Ann Anderson Vice President 2 [PHOTO APPEARS HERE] The San Juan Basin Royalty Trust is a New York Stock Exchange-listed entity, with Units trading under the symbol "SJT." [PHOTO APPEARS HERE] Cash distributions from the San Juan Basin Royalty Trust are declared and paid monthly to holders of its Units of beneficial interest. DESCRIPTION OF THE PROPERTIES The San Juan Basin properties from which the Trust's net overriding royalty interest was carved are located in San Juan, Rio Arriba and Sandoval counties of northwestern New Mexico (the "Underlying Properties"). The Underlying Properties contain 151,900 gross (119,000 net) producing acres and 3,038 gross (909 net) producing wells, including dual completions. "Gross" acres or wells, for purposes of this discussion, means the entire ownership interest of all parties in such properties, and BROG's interest therein is referred to as the "net" acres or wells. The Underlying Properties have historically produced gas primarily from conventional wells drilled to three major formations: the Pictured Cliffs, the Mesa Verde and the Dakota, ranging in depth from 1,500 to 8,000 feet. The characteristics of these reservoirs result in the wells having very long productive lives. A production index for oil and gas properties is the number of years derived by dividing remaining reserves by current production. Based upon the reserve report prepared by independent petroleum engineers as of December 31, 1997, the production index for the San Juan Basin properties is estimated to be approximately 8 years. The production index is subject to change from year to year based on reserve revisions and production levels. Among the factors considered by engineers in estimating remaining reserves of natural gas is the current sales price for gas. As the sales price increases, the producer can justify expending higher lifting costs and therefore reasonably expect to recover more of the known reserves. Accordingly, as gas prices rise the production index increases and vice versa. During 1988, a drilling program was initiated involving development of Fruitland Coal Seam gas reserves. Wells drilled in the Fruitland Coal Seam range in depth from 2,500 to 3,500 feet, generally on 320-acre spacing. BROG has informed the Trust that based on its success in 1997 it anticipates increasing the density of its drilling operations in the Fruitland Coal, with wells drilled on 160 and 80 -acre spacing. The process of removing coal seam gas is often referred to as degasification or desorption. Millions of years ago, natural gas was generated in the process of coal formation and adsorbed into the coal. Water later filled the natural fracture system. When the water is removed from the natural fracture system, reservoir pressure is lowered and the gas desorbs from the coal. The desorbed gas then flows through the fracture system and is produced at the well bore. The volume of formation water production typically declines with time and the gas production may increase for a period of time before starting to decline. In order to dispose of the formation water, surface facilities including pumping units are required, which results in the cost of a completed well being as much as $500,000. During 1997, these coal seam wells produced a total of approximately 9,570,183 MMBtu of gas from the Underlying Properties, which was sold at an average price of $2.03 per MMBtu. Production from coal seam wells drilled prior to January 1, 1993, qualifies for Federal income tax credits through 2002. For 1997 the credit was approximately $1.05 per MMBtu. During 1997, potential Section 29 tax credits of approximately $.215593 per Unit were generated for Trust Unit holders from production from coal seam wells. During 1997, BROG incurred approximately $7.2 million of capital expenditures for the drilling and completion of 64 gross (3.53 net) conventional wells, recompletion of 14 gross (5.4 net) conventional wells, drilling and completion of 1 gross (.84 net) coal seam well, and 21 gross (2.32 net) coal seam recavitations. There were 5 gross (1.22 net) new conventional wells, 3 gross (1.08 net) conventional recompletions, 11 gross (.42 net) coal seam recompletion, 5 gross (.20 net) coal seam recavitations, and 1 gross (.04 net) coal seam well in progress as of December 31, 1997. During 1996, BROG participated in the completion of 13 gross (1.96 net) conventional wells, drilling and recompletion of 8 gross (4.80 net) conventional wells as coal seam wells, recompleting 44 gross (12.96 net) conventional wells and other maintenance activities and facilities costs at a total cost of $9,409,000. Due to size of the coal seam drilling program in the San Juan Basin in the late 1980s by various operators, there was more gas deliverability than available pipeline capacity. As a result, several natural gas transportation companies commenced pipeline expansion projects which almost doubled the available transportation capacity out of the San Juan Basin. These projects were completed during 1992 and production increased to 26.6 Bcf for 1992 and to 40.7 Bcf for 1994. BROG has advised the Trustee that current mainline capacity out of the San Juan Basin is estimated at 3 Bcf per day for El Paso Natural Gas Pipeline and 1.5 Bcf per day for Transwestern Pipeline Company and that pipelines from the San Juan Basin are now capable of transporting approximately 1.2 Bcf per day to markets east of the San Juan Basin. 5 DESCRIPTION OF THE PROPERTIES Based on available geological and pricing information, the Trust has been advised that approximately 71 net conventional wells are projected to be drilled on the Underlying Properties. Proved undeveloped reserves have been assigned to these wells. BROG has advised the Trust that its 1998 capital projections for Trust working interests are estimated to be $10 million. Fruitland Coal is estimated to be approximately 15% of the total and the remainder would be conventional projects. Of the 300 planned projects, 47 will be conventional new drill locations at a cost of approximately $3.2 million. There are 47 planned Fruitland Coal recavitations at an estimated cost of $500,000, 39 of which will be in the 39-6 Federal Unit. BROG anticipates adding compressors to 56 Fruitland Coal wells at a cost of approximately $700,000. There are approximately 100 miscellaneous conventional projects planned, mostly projects aimed at improving production from existing wells, at a cost estimated to be $5 million. BROG anticipates that non-operated projects would be at a cost of approximately $600,000. Development plans are dependent upon numerous factors, including, but not limited to, drilling results of gas wells, anticipated demand for gas, the sales price of gas, cost to drill the wells and other factors that BROG may deem appropriate. The Federal Energy Regulatory Commission is primarily responsible for federal regulation of natural gas. For a further discussion of gas pricing, gas purchasers, gas production and regulatory matters affecting gas production see Item 2, "Properties" in the accompanying Form 10-K. [PHOTO APPEARS HERE] 6 TRUSTEE'S DISCUSSION AND ANALYSIS Distributable income consists of Royalty Income plus interest, less the general and administrative expenses of the Trust and any changes in cash reserves established by the Trustee. For the year ended December 31, 1997, distributable income increased to $48,648,930 from $37,803,167 distributed in 1996. The increase was primarily attributable to significantly higher gas prices. Interest income increased from $76,346 in 1996 to $99,403 in 1997 primarily due to increased funds available for investment. Total gas and oil production from the Underlying Properties for the five years ended December 31, 1997, were as follows:
- ------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1994 1993 ---------- ---------- ---------- ---------- ---------- Gas - Mcf_________________ 41,948,567 40,738,422 34,387,190 34,222,189 40,736,391 Mcf per day_______________ 114,928 111,307 94,211 93,759 111,607 Oil - Bbls________________ 89,492 83,552 75,014 84,648 88,466 Bbls per day______________ 245 228 206 232 242 - -------------------------------------------------------------------------------------------------------------------
Since the oil and gas sales attributable to the Royalty are based on an allocation formula dependent on such factors as price and cost, including capital expenditures, the aggregate volumes from the Underlying Properties may not provide a meaningful comparison to volumes attributable to the Royalty. Royalty Income for the calendar year is associated with actual gas and oil production during the period from November of the preceding year through October of the current year. Gas and oil sales attributable to the royalty for the past five years, (excluding portions attributable to the litigation settlement proceeds described in Note 5 to accompanying Financial Statements), are summarized in the following table:
- ------------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1994 1993 ----------- ----------- ----------- ----------- ----------- Gas - Mcf_________________ 24,236,419 17,927,785 13,331,758 15,459,542 23,895,506 Average Price (per Mcf)___ $2.21 $1.30 $1.25 $1.66 $1.70 Oil - Bbls________________ 50,860 36,792 29,424 36,769 51,921 Average Price (per Bbl)___ $19.35 $19.64 $14.43 $13.09 $15.58 - -------------------------------------------------------------------------------------------------------------------
The fluctuations in annual gas production that have occurred during these five years generally resulted from changes in the demand for gas during that time, marketing conditions and production from new wells. Production from the Underlying Properties is influenced by the line pressures of the gas gathering systems in the San Juan Basin. Expansion during 1992 of the gas transmission systems that transport gas out of the San Juan Basin resulted in increased production beginning in 1992. Higher volumes in 1993 can be partially attributed to gas balancing in the San Juan 30-6 Federal Unit which occurred in the 3rd and 4th quarters of 1993. Production from the 30-6 Unit was more normalized beginning in 1994. Production increased from 1995 to 1996 primarily due to increased coal seam volumes. 7 TRUSTEE'S DISCUSSION AND ANALYSIS Royalty Income for the five years ended December 31, 1997, was determined as shown in the following table:
- ----------------------------------------------------------------------------------------------------------------- 1997 1996 1995 1994 1993 ----------- ----------- ----------- ----------- ----------- GROSS PROCEEDS FROM THE UNDERLYING PROPERTIES: - -------------------------- Gas_______________________________ $91,495,060 $51,865,730 $41,483,305 $54,375,586 $69,266,623 Oil_______________________________ 1,728,296 1,638,753 1,084,262 1,140,738 1,384,468 Other_____________________________ -0- -0- -0- -0- -0- ----------- ----------- ----------- ----------- ----------- Total___________________________ 93,223,356 53,504,483 42,570,159 55,498,324 70,651,091 =========== =========== =========== =========== =========== LESS PRODUCTION COSTS: - --------------------- Capital Costs ____________________ 7,231,696 7,223,281 6,560,277 9,409,462 3,988,136 Severance Tax - Gas_______________ 8,989,202 5,654,831 4,694,750 5,864,834 6,543,615 Severance Tax - Oil ______________ 167,844 176,379 115,474 117,028 153,072 Other_____________________________ 61,832 59,089 117 -0- -0- Leasing Operating Expenses________ 10,776,145 11,838,345 10,991,152 9,066,750 9,864,773 ----------- ----------- ----------- ----------- ----------- Total___________________________ 27,226,719 24,951,925 22,361,770 24,458,074 20,549,596 ----------- ----------- ----------- ----------- ----------- Net Profits_______________________ 65,996,637 28,552,558 20,208,389 31,040,250 50,101,495 Royalty Percentage_______________ 75% 75% 75% 75% 75% Royalty Income____________________ $49,497,479 $21,414,419 $15,156,292 $23,280,188 $37,576,121 =========== =========== =========== =========== =========== - -----------------------------------------------------------------------------------------------------------------
The higher capital costs in 1994 were primarily attributable to recompletions into the coal seam as part of a program which was initiated in 1988. The capital costs incurred by BROG on the Underlying Properties for the year ended December 31, 1997, amounted to $7,231,696 versus $7,223,281 for 1996. The increase was primarily attributable to increased drilling activity. The Royalty Income amount of $21,414,419 for 1996 does not include the $19,822,005 paid to the Trust on September 30, 1996, in settlement of the litigation described in Note 5 to the accompanying Financial Statements. Operating costs in 1997 include the impact of the receipt of $250,000 from BROG as an offset to lease operating expense in connection with the settlement of that litigation. Excluding the impact of the offset, monthly operating costs in 1997 averaged approximately $899,000, which is lower than the $955,000 average in 1996. 8 Distributable income for three months ended December 31, 1997, totaled $12,211,435 ($.261999 per Unit) as compared to $8,143,076 ($.174711 per Unit) for the quarter ended December 31, 1996. The amount distributed in the fourth quarter of 1997 was higher than that of 1996 primarily because of the higher average gas prices. Royalty Income of the Trust for the fourth quarter is associated with actual gas and oil production during August through October of each year. Gas and oil sales for the quarters ended December 31, 1997 and 1996 were as follows: - -------------------------------------------------------------------------------- UNDERLYING PROPERTIES 1997 1996 - -------------------- ---------- ---------- Gas - Mcf___________________________ 10,441,818 10,535,177 Average Price (per Mcf)___________ $2.15 $1.64 Oil - Bbls__________________________ 19,438 19,460 Average Price (per Bbl)___________ $17.90 $21.06 ATTRIBUTABLE TO ROYALTY - ----------------------- Gas - Mcf____________________________ 6,113,834 5,478,137 Oil - Bbls___________________________ 11,400 10,260 - -------------------------------------------------------------------------------- The average price of gas increased the fourth quarter of 1997 primarily due to increases in spot prices. The average of oil decreased compared to the prior year. Gas production decreased slightly primarily due to a decrease in coal seam production. During the fourth quarter of 1997, coal seam production from the Underlying Properties averaged 1,547,000 Mcf per month compared to 1,728,000 Mcf per month during the fourth quarter of 1996. Capital costs for the fourth quarter of 1997 totaled $1,579,932 compared to $1,996,490 during the same period of 1996. The decrease was due to a decrease in drilling activity in the fourth quarter of 1997. Operating costs in 1997 include the impact of the receipt of $250,000 from BROG as an offset to lease operating expense in connection with the settlement of litigation. Excluding the impact of the offset, lease operating costs for the fourth quarter of 1997 averaged $858,000 per month compared to $926,000 per month in the fourth quarter of 1996. 9 SAN JUAN BASIN ROYALTY TRUST Statements of Assets, Liabilities and Trust Corpus December 31, 1997 and 1996
- ------------------------------------------------------------------------------------------------------------ ASSETS 1997 1996 - ------ ----------- ----------- Cash and Short-term investments______________________________ $ 5,111,832 $ 3,127,828 Net Overriding Royalty Interests in Producing Oil and Gas Properties - Net (Notes 2 and 3)_____________________ 56,119,448 62,808,148 ----------- ----------- $61,231,280 $65,935,976 =========== =========== LIABILITIES AND TRUST CORPUS - ---------------------------- Distribution Payable to Unit Holders_________________________ $ 5,111,832 $ 3,127,828 Contingencies (Note 5) Trust Corpus - 46,608,796 Units of Beneficial interest Authorized and Outstanding______________________________ 56,119,448 62,808,148 ----------- ----------- $61,231,280 $65,935,976 =========== =========== - ------------------------------------------------------------------------------------------------------------
Statements of Distributable Income for the Three Years Ended December 31, 1997
- ------------------------------------------------------------------------------------------------------------ 1997 1996 1995 ------------ ----------- ----------- Royalty Income (Notes 2, 3 and 5)____________________________ $ 49,497,479 $41,236,424 $15,156,292 Interest Income______________________________________________ 99,403 76,346 31,978 ------------ ----------- ----------- 49,596,882 41,312,770 15,188,270 Expenditures - General and Administrative____________________ 947,952 3,509,603 1,398,169 ------------ ----------- ----------- Distributable Income_________________________________________ $ 48,648,930 $37,803,167 $13,790,101 ============ =========== =========== Distributable Income per Unit (46,608,796 Units)_____________ $ 1.043770 $ .811072 $ .295867 ============ =========== =========== - ------------------------------------------------------------------------------------------------------------
Statements of Changes in Trust Corpus for the Three Years Ended December 31, 1997
- ------------------------------------------------------------------------------------------------------------ 1997 1996 1995 ------------ ----------- ----------- Trust Corpus, Beginning of Period____________________________ $ 62,808,148 $70,133,536 $74,942,040 Amortization of Net Overriding Royalty Interest (Notes 2 and 3)___________________________________________ (6,688,700) (7,325,388) (4,808,504) Distributable Income_________________________________________ 48,648,930 37,803,167 13,790,101 Distributions Declared_______________________________________ (48,648,930) (37,803,167) (13,790,101) ============ =========== =========== Trust Corpus, End of Period__________________________________ $ 56,119,448 $62,808,148 $70,133,536 ============ =========== =========== - ------------------------------------------------------------------------------------------------------------
The accompanying Notes to Financial Statements are an integral part of these statements. 10 SAN JUAN BASIN ROYALTY TRUST NOTES TO FINANCIAL STATEMENTS 1. TRUST ORGANIZATION AND PROVISIONS The San Juan Basin Royalty Trust ("Trust") was established as of November 1, 1980. Bank One, Texas, N.A. ("Trustee") is Trustee for the Trust. Southland Royalty Company ("Southland") conveyed to the Trust a 75% net overriding royalty interest ("Royalty") in Southland's working interests and royalty interests in the San Juan Basin in northwestern New Mexico. On November 3, 1980, units of beneficial interest ("Units") in the Trust were distributed to the Trustee for the benefit of Southland shareholders of record as of November 3, 1980, who received one Unit in the Trust for each share of Southland common stock held. The Units are traded on the New York Stock Exchange. The terms of the Trust Indenture provide, among other things, that: . The Trust shall not engage in any business or commercial activity of any kind or acquire any assets other than those initially conveyed to the Trust; . the Trustee may not sell all or any part of the Royalty unless approved by holders of 75% of all Units outstanding, in which case the sale must be for cash and the proceeds promptly distributed; . the Trustee may establish a cash reserve for the payment of any liability which is contingent or uncertain in amount; . the Trustee is authorized to borrow funds to pay liabilities of the Trust; and . the Trustee will make monthly cash distributions to Unit holders (see Note 2). 2. NET OVERRIDING ROYALTY INTEREST AND DISTRIBUTION TO UNIT HOLDERS The amounts to be distributed to Unit holders ("Monthly Distribution Amounts") are determined on a monthly basis. The Monthly Distribution Amount is an amount equal to the sum of cash received by the Trustee during a calendar month attributable to the Royalty, any reduction in cash reserves and any other cash receipts of the Trust, including interest, reduced by the sum of liabilities paid and any increase in cash reserves. If the Monthly Distribution Amount for any monthly period is a negative number, then the distribution will be zero for such month. To the extent the distribution amount is a negative number, the amount will be carried forward and deducted from future monthly distributions until the cumulative distribution calculation becomes a positive number, at which time a distribution will be made. Unit holders of record will be entitled to receive the calculated Monthly Distribution Amount for each month on or before ten business days after the monthly record date, which is generally the last business day of each calendar month. The cash received by the Trustee consists of the amounts received by the owner of the interest burdened by the Royalty from the sale of production less the sum of applicable taxes, accrued production costs, development and drilling costs, operating charges and other costs and deductions, multiplied by 75%. Royalty income for 1996 was comprised of $21,414,419, which represents the net overriding royalty interest in the net profits of the properties from which the net overriding royalty was carved, and $19,822,005 paid to the Trust as a result of the settlement of litigation involving the Trustee, Meridian Oil Inc. ("MOI") and Southland. For more information regarding the settlement of the litigation, see Note 5. The initial carrying value of the Royalty ($133,275,528) represented Southland's historical net book value at the date of the transfer to the Trust. Accumulated amortization as of December 31, 1997 and 1996 aggregated $77,156,080 and $70,467,380, respectively. 3. BASIS OF ACCOUNTING The financial statements of the Trust are prepared on the following basis: . Royalty income recorded for a month is the amount computed and paid by the working interest owner, Southland, to the Trustee on behalf of the Trust. Royalty income consists of the amounts received by the owner of the interest burdened by the net overriding royalty interest from the sale of production less accrued production costs, development and drilling costs, applicable taxes, operating charges, and other costs and deductions, multiplied by 75%. . Trust expenses recorded are based on liabilities paid and cash reserves established from Royalty income for liabilities and contingencies. . Distributions to Unit holders are recorded when declared by the Trustee. . The conveyance which transferred the overriding royalty interests to the Trust provides that any excess of production costs over gross proceeds must be recovered from future net profits. The financial statements of the Trust differ from financial statements prepared in accordance with generally accepted accounting principles ("GAAP") because revenues are not accrued in the month of production and certain cash reserves 11 SAN JUAN BASIN ROYALTY TRUST may be established for contingencies which would not be accrued in financial statements prepared in accordance with GAAP. Amortization of the Royalty calculated on a unit-of-production basis is charged directly to trust corpus. 4. FEDERAL INCOME TAXES For Federal income tax purposes, the Trust constitutes a fixed investment trust which is taxed as a grantor trust. A grantor trust is not subject to tax at the trust level. The Unit holders are considered to own the Trust's income and principal as though no trust were in existence. The income of the Trust is deemed to have been received or accrued by each Unit holder at the time such income is received or accrued by the Trust rather than when distributed by the Trust. The Royalty constitutes an "economic interest" in oil and gas properties for Federal income tax purposes. Unit holders must report their share of the revenues of the Trust as ordinary income from oil and gas royalties, and are entitled to claim depletion with respect to such income. The Royalty is treated as a single property for depletion purposes. The Trust has on file technical advice memoranda confirming the tax treatment described above. The Trust began receiving royalty income from coal seam wells beginning in 1989. Under Section 29 of the Internal Revenue Code, production from coal seam gas wells drilled prior to January 1, 1993, qualifies for the Federal income tax credit for producing non-conventional fuels. Production from coal seam wells drilled prior to January 1, 1993, qualifies for Federal income tax credits through 2002. Production from wells drilled after December 31, 1979, but prior to January 1, 1993, to a formation beneath a qualifing coal seam formation which are later completed into such formation, also qualifies for the tax credit. This tax credit was approximately $1.05 per MMBtu for the year 1997 and is adjusted for inflation annually. The credit currently applies to production through the year 2002. Each Unit holder must determine his pro rata share of such production based upon the number of Units owned during each month of the year and 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. The classification of the Trust's income for purposes of the passive loss rules may be important to a Unit holder. As a result of the Tax Reform Act of 1986, royalty income will generally be treated as portfolio income and will not reduce passive losses. 5. LITIGATION SETTLEMENT On June 4, 1992, the Trustee filed suit (the "Litigation") against MOI and Southland in New Mexico. The principal asset of the Trust consists of a 75% net overriding royalty interest carved out of certain of Southland's oil and gas leasehold and royalty interests in the San Juan Basin located in San Juan, Rio Arriba and Sandoval counties of northwestern New Mexico (the "Underlying Properties"). MOI and Southland were the operators of the Underlying Properties. On January 2, 1996, Southland was merged with and became a wholly owned subsidiary of MOI. Subsequent to the merger, MOI changed its name to Burlington Resources Oil & Gas Company ("BROG"). The claims asserted on behalf of the Trust in the lawsuit 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 a permanent injunction relating to the operation of the Underlying Properties. On September 4, 1996, the Trustee announced the settlement of the Litigation. The Litigation was dismissed on September 12, 1996. BROG denied and continues to deny the allegations made against it in the Litigation, but the parties 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. 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 that will 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 gas, oil and natural gas liquids products from the Underlying Properties going forward as follows: 12 [PHOTO APPEARS HERE] The Trust made distributions total- ing $1.04377 per Unit of beneficial interest in 1997. SAN JUAN BASIN ROYALTY TRUST [MAP OF SAN JUAN BASIN APPEARS HERE] 1. BROG's pre-existing contract with a third-party purchaser covering baseload gas volumes in the firm amount of 45,000 MMBtu per day remained effective for a period of one year from July 1, 1996. The remaining volumes of gas from the Underlying Properties were marketed by an independent marketer, El Paso Energy Marketing Company, a subsidiary of El Paso Energy Corporation, beginning October 1, 1996. BROG agreed that subsequent contracts for the sale of gas from the Underlying Properties would require the written approval of an independent gas marketing consultant acceptable to the Trust. For a discussion of the current contract covering the sale of gas from the Underlying Properties, see Note 6. 2. BROG will continue to market the Trust oil and natural gas liquids but will remit to the Trust 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. 3. The Trust retained access to BROG's current gas transportation, gathering, processing and treating agreements with third parties through the remainder of their primary terms. Additionally, El Paso could utilize BROG's eastern transportation agreement for delivery from the San Juan Basin on El Paso Natural Gas Company pipeline to pipelines in West Texas of up to 13,333 MMBtu per day of gas produced from Underlying Properties for a period of one year commencing October 1, 1996. The $19,822,005 settlement proceeds of the Litigation (or $.425285 per Unit of beneficial interest) was paid to the Trust on September 30 and distributed on October 15, 1996, to Unit holders 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. 6. CERTAIN CONTRACTS Southland entered into five-year gas, gas processing and gas gathering agreements with Sunterra Gas Gathering Company (a subsidiary of Public Service Company of New Mexico) ("Sunterra") and Gas Company of New Mexico (a division of Public Service Company of New Mexico) ("Gas Company") that were effective as of July 1,1990. The new contracts applied to all lands previously dedicated to Sunterra and Gas Company for first sales of natural gas sold into interstate or intrastate markets, except that the new gas purchase contracts excluded all gas produced and sold from coal seam wells. The new gas purchase contracts provided for purchases by Sunterra and Gas Company for winter heating season only. During the remainder of the year, Southland could market the gas through any arrangements it deemed advisable. Under the new gas purchase contracts, Southland received prices, inclusive of severance taxes, ranging from approximately $2.35 per MMBTu to $3.37 per MMBtu over the life of the contracts. The contracts also provided for certain "take-or-pay obligations" if certain minimum levels of natural gas sales are not reached. In 1991, due to the low level of natural gas prices, Sunterra informed Southland that it would not take any significant volume of gas during the 1991- 1992 winter heating season and would simply pay the "take-or-pay obligation" amount. Consequently, the majority of the wells subject to the contracts would have remained shut-in during the winter heating season. In an attempt to maximize production and revenues from the Underlying Properties, Southland informed the Trustee that it entered into an agreement with Sunterra and Gas Company that amended the terms of the contracts discussed above for only the 1991-1992 winter heating season. The amendment provided that Sunterra and Gas Company could purchase approximately 35% of the contract provided take levels at a wellhead price slightly higher than the spot market well-head index price for the San Juan Basin. Any gas purchased by Sunterra and Gas Company above this level averaged $2.63 per MMBtu. Southland was free to market the remaining deliverable gas to other purchasers. During 1992, Sunterra and Gas Company purchased 3,241,550 Mcf and 702,629 Mcf, respectively, at average prices of $1.98 and $2.25 per Mcf, respectively, from the Underlying Properties. To continue to maximize production and revenues from Trust Properties, Southland again informed the Trustee that it negotiated an agreement with Sunrerra and Gas Company that amended the terms of the original contracts discussed above for only the 1992-1993 winter heating season. The amendment provided that Gas Company and Sunterra were required to purchase a minimum of 11,500 MMBtu per day at $2.695 per MMBtu under the intrastate and a minimum of 16,550 MMBtu per day at $2.94 per MMBtu under the interstate contracts. A portion of the excess gas 14 SAN JUAN BASIN ROYALTY TRUST was released for spot sales, with a recall provision at an average contract price. Southland informed the Trust that a similar amendment was entered into for the 1993-1994 winter heating season. Gas Company and Sunterra paid the contract specified prices of $2.88 and $3.15 per MMBtu, respectively, on a minimum purchase of 1.4 Bcf and 1.2 Bcf, respectively. All remaining gas was released for spot sales with a recall provision at an average contract price. Southland waived any claims for deficiency payment under the reservation fee. Southland informed the Trust an amendment had also been entered into for the 1994-1995 winter heating season. Gas Company and Sunterra were required to purchase, at the wellhead, an average volume of 10,529 MMBtu per day at $2.884 per MMBtu for the period beginning November 1,1994, and ending March 31, 1995, and an additional 14,900 MMBtu per day at $3.146 per MMBtu for the period beginning December 1, 1994, and ending February 28, 1995. Gas Company and Sunterra were granted a make-up period of four months beginning April 1, 1995, to fulfill this purchase obligation. Gas Company and Sunterra were also granted recall rights on volumes up to 15,000 MMBtu per day at the tailgate of the Kutz and Lybrook plants, provided they nominated the full contract volume specified above. The price for recall gas was the average of the first and second issues of the Inside FERC EPNG SJ Index. The Trust was advised that effective July 1, 1995, Williams Field Services ("Williams") purchased the Kutz and Lybrook processing plants and the gathering systems behind these plants which were owned by Sunterra, Gas Company and Sunterra Gas Processing Company ("SGPC") and that new gathering and processing agreements with Williams were entered into which contain acceptable rates, terms and conditions. The new agreements replaced the then current gathering and processing agreements with Gas Company, Sunterra and SGPC effective on the closing date of the sale of these facilities to Williams. The gas purchase contracts described in Note 5 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 Energy Marketing Company ("El Paso"). That contract is for a term of two years through and including December 31, 1999 and provides 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. While it is impossible to predict the exact economic value of gas contracts, the Trust has been advised by its independent gas marketing consultant that the contract with El Paso should provide for the average highest sales price for natural gas in the San Juan Basin over the two- year term of the 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. 7. SIGNIFICANT CUSTOMERS Information as to significant purchasers of oil and gas production attributable to the Trust's economic interests is included in Item 2 of the Trust's annual report on Form 10-K which is included in this report. 8. PROVED OIL AND GAS RESERVES (UNAUDITED) Proved oil and gas reserve information is included in Item 2 of the Trust's annual report on Form 10-K which is included in this report. 9. QUARTERLY SCHEDULE OF DISTRIBUTABLE INCOME (UNAUDITED) The following is a summary of the unaudited quarterly schedule of distributable income for the two years ended December 31, 1997 (in thousands, except unit amounts): ============================================================= Distributable Income and Royalty Distributable Distribution 1997 Income Income Per Unit - ---- ------- ------------- ------------- First Quarter_________ $18,471 $18,267 $ .391930 Second Quarter________ 8,900 8,565 .183766 Third Quarter_________ 9,764 9,605 .206076 Fourth Quarter________ 12,363 12,212 .261998 ------ ------ --------- Total_______________ $49,498 $48,649 $1.043770 ======= ======= ========= 1996 - ---- First Quarter_________ $ 4,708 $ 3,926 $ .084239 Second Quarter________ 4,408 2,943 .063143 Third Quarter_________ 24,135 22,791 .488979 Fourth Quarter________ 8,345 8,143 .174711 ------- ------- --------- Total_______________ $41,236 $37,803 $ .811072 ======= ======= ========= ============================================================= 15 INDEPENDENT AUDITORS' REPORT Bank One, Texas, N.A. as Trustee for the San Juan Basin Royalty Trust: We have audited the accompanying statements of assets, liabilities and trust corpus of the San Juan Basin Royalty Trust ("Trust") as of December 31, 1997 and 1996, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1997. These financial statements are the responsibility of the Trustee. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by the Trustee, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. As described in Note 3 to the financial statements, these financial statements were prepared on a modified cash basis, which is a comprehensive basis of accounting other than generally accepted accounting principles. In our opinion, such financial statements present fairly, in all material respects, the assets, liabilities and trust corpus of the San Juan Basin Royalty Trust as of December 31, 1997 and 1996, and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1997, on the basis of accounting described in Note 3. /s/ DELOITTE & TOUCHE LLP Deloitte & Touche LLP Fort Worth, Texas March 25, 1998 - -------------------------------------------------------------------------------- SAN JUAN BASIN ROYALTY TRUST TAX COUNSEL Bank One, Texas, NA., Trustee Butler & Binion, L.L.P. Post Office Box 2604 Houston, Texas Fort Worth, Texas 76113 817-884-4630 Web site: www.sjbrt.com TRANSFER AGENT Harris Trust & Savings Bank AUDITORS 311 West Monroe Street, 11th Floor Chicago, Illinois 60606 Deloitte & Touche LLP Fort Worth, Texas For questions about distribution checks, address changes, and transfer procedures, call 800-573-4048 or LEGAL COUNSEL 312-461-6001. Vinson & Elkins L.L.P Dallas, Texas 16 EX-23 3 CONSENT OF CAWLEY, GILLESPIE & ASSOCIATES, INC. EXHIBIT 23 MARCH 27, 1998 San Juan Basin Royalty Trust Bank One, Texas, N.A. 7th Floor, Suite 704 Fort Worth, Texas 76102 Gentlemen: Cawley, Gillespie & Associates, Inc. hereby consents to the use of the oil and gas reserve information in the San Juan Basin Royalty Trust Securities & Exchange Commission Form 10-K for the year ended December 31, 1997 and in the San Juan Basin Royalty Trust Annual Report for the year ended December 31, 1997 based on reserve reports dated March 25, 1998 prepared by Cawley, Gillespie & Associates, Inc. Sincerely, /s/ CAWLEY, GILLESPIE & ASSOCIATES, INC. Cawley, Gillespie & Associates, Inc. EX-27 4 FINANCIAL DATA SCHEDULE
5 THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE UNAUDITED CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS OR SAN JUAN BASIN ROYALTY TRUST AS OF DECEMBER 31, 1997, AND THE RELATED CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE-MONTH PERIOD ENDED DECEMBER 31, 1997. 12-MOS DEC-31-1997 DEC-31-1997 5,111,832 0 0 0 0 5,111,832 133,275,528 77,156,080 61,231,280 5,111,832 0 0 0 0 56,119,448 61,231,280 0 49,596,882 0 0 947,952 0 0 48,648,930 0 48,648,930 0 0 0 48,648,930 0 0
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