-----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, WRKgyK6Yh4MlMmreXT0aNHFk3e3ZlVxfsSnja0Zkv2TGIiZtrC9sv68Zkrq/Zg8H ZcPzCU8rht0XKhR9tXHk7g== 0000899243-97-000514.txt : 19970401 0000899243-97-000514.hdr.sgml : 19970401 ACCESSION NUMBER: 0000899243-97-000514 CONFORMED SUBMISSION TYPE: 10-K405 PUBLIC DOCUMENT COUNT: 4 CONFORMED PERIOD OF REPORT: 19961231 FILED AS OF DATE: 19970331 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: 1934 Act SEC FILE NUMBER: 001-08032 FILM NUMBER: 97568658 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 (Fee Required) For the fiscal year ended December 31, 1996, or [_] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 (No Fee Required) 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) 76113 BANK ONE, TEXAS, NA (Zip Code) TRUST DEPARTMENT 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 UNITS OF BENEFICIAL INTEREST REGISTERED 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, 1997, there were 46,608,796 Units of Beneficial Interest of the Trust outstanding with an aggregate market value on that date of $367,044,269. DOCUMENTS INCORPORATED BY REFERENCE "Units of Beneficial Interest" at page 2; "Description of the Properties" at page 4; "Trustee's Discussion and Analysis" at pages 6 and 7; "Results of the 4th Quarters of 1996 and 1995" 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, 1996 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, NA. The principal office of the Trust (sometimes referred to herein as the "Registrant") is located at 500 Throckmorton Street, Suite 704, Fort Worth, Texas 76102 (telephone number 817/844-4630). 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 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. 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. 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, subject to certain adjustments. "Production costs" means, generally, costs incurred on an accrual basis by BROG in operating its properties and interests out of which the Royalty was carved, including both capital and non-capital costs. For example, these costs include development drilling, production and processing costs, applicable taxes, and operating charges. If production costs exceed gross proceeds in any month, the excess is recovered out of future gross proceeds prior to the making of further payment to the Trust, but the Trust is not otherwise liable for any production costs or other costs or liabilities attributable to these properties and interests or the minerals produced therefrom. If at any time the Trust receives more than the amount due under the Royalty, it shall not be obligated to return such overpayment, but the amounts payable to it for any subsequent period shall be reduced by such amount, plus interest, at a rate specified in the conveyance. 1 Certain of the properties and interests out of which the Royalty was carved 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 and interests, either under existing sales contracts or under future arrangements at the best prices and on the best terms it shall deem reasonable 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 properties from which the Royalty was carved. 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 properties from which the Royalty was carved 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. ITEM 2. PROPERTIES The 75% net overriding royalty conveyed to the Trust was carved out of Southland Royalty's working interest and royalty interests in the San Juan Basin in northwestern New Mexico. References below to "net" wells and acres are to the interests of BROG (from which the Royalty was carved) in the "gross" wells and acres. Unless otherwise indicated, the following information in Item 2 is based upon data and information furnished the Trustee by BROG. PRODUCING ACREAGE, WELLS AND DRILLING BROG's working interests and royalty interests in the San Juan Basin consist of 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 3,180 gross (960 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, 1996, is herein incorporated by reference. 2 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 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. During 1995, there were 24 gross (6.36 net) wells completed including 5 gross (2.54 net) coal seam wells. There were 4 gross (1.89 net) coal seam wells and 7 gross (2.24 net) conventional wells in progress at December 31, 1995. There were 24 gross (11.41 net) coal seam wells and 38 gross (8.61 net) conventional wells recompleted through December 31, 1995. During 1994, there were 21 gross (6.76 net) wells completed including 8 gross (4.80 net) coal seam wells. There were 4 gross (2.55 net) coal seam wells and 23 gross (7.69 net) conventional wells in progress at December 31, 1994. There were 17 gross (10.57 net) coal seam wells and 44 gross (12.96 net) conventional wells recompleted through December 31, 1994. 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, 1996 were as follows:
1996 1995 1994 ----------------- ------------------ ------------------ OIL GAS OIL GAS OIL GAS (BBLS) (MCF) (BBLS) (MCF) (BBLS) (MCF) ------ ---------- ------ ---------- ------ ---------- Production................ 36,792 17,927,785 29,424 13,331,758 36,769 15,459,542 Average Price............. $19.64 $1.30 $14.43 $1.25 $13.09 $1.66
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 40,738,422 Mcf during 1996. 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. 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 3 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 shall receive 75% (the amount of its net overriding royalty interest) of any value that ultimately inures 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, 1996 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. 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 4 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. Southland Royalty also informed the Trust 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 have been 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 Trust has further been informed by Southland Royalty that MOTI negotiated an agreement with Gas Company providing for transportation service on Gas Company's Albuquerque mainline. This agreement was effective on the closing date of the sale of Gas Company's gathering and processing facilities to Williams. This transportation agreement facilitates delivery of volumes of gas behind the Lybrook processing plant to mainline delivery points. Southland Royalty further informed the Trust that on September 13, 1994, MOTI entered into a gas sales agreement with Gas Company for the five winter periods beginning November 1, 1995 and ending March 31, 5 2000. MOTI purchased the gas supplied for this sale from MOI producing affiliates and third party sellers. Sales were based on a monthly published index. BROG has informed the Trust that as a result of the Litigation (as hereinafter defined), no gas produced from the properties from which the Royalty was carved will be applied in performance of such agreement with Gas Company. It is the understanding of the Trustee that Gas Company is now known as PNM Gas Services. On September 4, 1996, the Trustee announced the settlement of the litigation (the "Litigation") filed by the Trustee against BROG and Southland Royalty Company. The Litigation, which was filed in the state district court of Santa Fe County, New Mexico, Cause No. SF 94-1982(c), was dismissed on September 12, 1996. Agreement was reached, among other things, regarding marketing arrangements for the sale of Trust gas, oil and natural gas liquids products going forward as follows: (i) BROG's pre-existing contract with a third-party purchaser will continue as pertains to baseload gas volumes in the firm amount of 45,000 MMBtus/day for a period of one year from July 1, 1996. Negotiations for the sale of these volumes after June 30, 1997, will be entered into prior to the expiration of the primary term of the contract; (ii) The remaining volumes of Trust gas will be marketed by an independent marketer, El Paso Energy Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation, beginning October 1, 1996, under an arrangement which provides for a sharing of amounts, if any, earned in excess of established gas price thresholds. El Paso's compensation for its marketing services consists solely of its proportionate part of any amounts for which the gas is sold in excess of the thresholds. BROG's contract with El Paso is for a two-year term beginning October 1, 1996, subject to renewal by agreement of the parties; (iii)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 (iv) 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 may 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. See Note 5 of Notes to Financial Statements of the Trust's Annual Report to securityholders for the year ended December 31, 1996 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 6 federal regulation) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less estimated future expenditures (based on current costs) to be incurred in developing and producing the proved reserves, and assuming continuation of existing economic conditions. "Estimated future net revenues" are sometimes referred to herein as "estimated future net cash flows." "Present value of estimated future net revenues" is computed using the estimated future net revenues and a discount rate of 10%. The independent petroleum engineers' reports as to the proved oil and gas reserves as of December 31, 1994, 1995 and 1996 were prepared by Cawley, Gillespie & Associates, Inc. The following table presents a reconciliation of proved reserve quantities attributable to the Royalty from December 31, 1993 to December 31, 1996 (in thousands);
NATURAL OIL GAS (BBLS) (MCF) ------ ------- Reserves as of December 31, 1993......................... 712 248,101 Revisions of previous estimates.......................... (63) (31,236) Extensions, discoveries and other additions.............. -0- -0- Production............................................... (37) (15,460) ---- ------- 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 ==== =======
Estimated quantities of proved developed reserves of crude oil and natural gas as of December 31, 1996, 1995 and 1994 were as follows (in thousands):
CRUDE NATURAL OIL GAS (BBLS) (MCF) ------ ------- 1996....................................................... 637 239,962 1995....................................................... 418 159,650 1994....................................................... 612 186,915
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. 7 Estimates of proved oil and gas reserves are by their nature imprecise. Estimates of future net revenue attributable to proved reserves are sensitive to the unpredictable prices of oil and gas and other variables. Accordingly, under the allocation method used to derive the Trust's quantity of proved reserves, changes in prices will result in changes in quantities of proved oil and gas reserves and estimated future net revenues. The 1996, 1995 and 1994 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):
1996 1995 1994 -------- -------- -------- Balance, January 1......................... $106,937 $157,627 $274,215 Revisions of prior-year estimates, change in prices and other....................... 338,208 (51,819) (120,730) Extensions, discoveries and other additions................................. 4,612 522 -0- Accretion of discount...................... 10,694 15,763 27,422 Royalty income............................. (21,414) (15,156) (23,280) -------- -------- -------- Balance, December 31....................... $439,037 $106,937 $157,627 ======== ======== ========
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 $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 downward revision is primarily due to lower gas prices in 1995. An average price of $1.56 per Mcf and $13.78 per barrel were used at December 31, 1994, in determining estimated future net revenues. The downward revision was primarily due to lower gas prices in 1994. 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, 1996, 1995 and 1994 (in thousands except amounts per Unit):
1996 1995 1994 ------------------ ------------------ ------------------ 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.......... $822,131 $439,037 $184,055 $106,937 $287,401 $157,627 Proved Developed...... $799,664 $430,365 $175,824 $104,378 $265,477 $149,241 Total Proved Per Unit. $ 17.64 $ 9.42 $ 3.95 $ 2.29 $ 6.17 $ 3.38
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, 8 the present values shown above should not be considered as the market values of such oil and gas reserves or the costs that would be incurred to acquire equivalent reserves. A market value determination would include many additional factors. REGULATION Many aspects of the production, pricing and marketing of crude oil and natural gas are regulated by federal and state agencies. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden on affected members of the industry. Exploration and production operations are subject to various types of regulation at the federal, state and local levels. Such regulation includes requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Natural gas and oil operations are also subject to various conservation laws and regulations that regulate the size of drilling and spacing units or proration units and the density of wells which may be drilled and unitization or pooling of oil and gas properties. In addition, state conservation laws establish maximum allowable production from natural gas and oil wells, generally prohibit the venting or flaring 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 ("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. Commencing in 1992, FERC issued Orders Nos. 636, 636-A, 636-B and 636-C (collectively, "Order No. 636"), which generally opened access to interstate gas pipelines by requiring such pipelines to "unbundle" their transportation services and allow shippers to choose and pay for only the services they require, regardless of whether the shipper purchases gas from such pipelines or from other suppliers. These orders also require upstream pipelines to permit downstream pipelines to assign upstream capacity to their shippers and place analogous, unbundled access requirements on the downstream pipelines. Through individual pipeline restructuring proceedings, Order No. 636 has been implemented on all U.S. interstate pipelines. There are currently a number of judicial challenges to these individual proceedings, which are now pending before the U.S. Court of Appeals for the District of Columbia Circuit (the "D.C. Circuit"). In July 1996, the D.C. Circuit largely upheld the terms of the Order No. 636 rulemaking. Certain aspects of the D.C. Circuit's ruling have been appealed to the U.S. Supreme Court. Although Order No. 636 does not regulate the Trust, FERC has stated that Order No. 636 is intended to foster increased competition within all phases of the natural gas industry. In many instances, the result of Order No. 636 and related initiatives have been to substantially reduce or eliminate the interstate pipelines' traditional role as wholesalers of natural gas in favor of providing only storage and transportation services. It is unclear what impact, if any, increased competition within the natural gas industry under Order No. 636 will have on the Trust. The FERC has recently announced its intention to reexamine certain of its transportation-related policies, including the appropriate manner for setting rates for new interstate pipeline construction, the manner in which 9 interstate pipeline shippers may release interstate pipeline capacity under Order No. 636 for resale in the secondary market, and the use of market-based rates for interstate gas transmission. While any resulting FERC action would affect the Trust only indirectly, FERC's stated intention is to further enhance competition in natural gas markets. 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. 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 a qualifying coal seam formation which are later completed into such formation also qualifies for the tax credit. This tax credit for 1996 was approximately $1.03 per MMBtu and 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 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 taxypayer'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 Trust 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 Trust 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. 10 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 unit holders 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, Notes 5 and 6 of the Notes to Financial Statements at pages 13 through 15 of the Trust's Annual Report to security holders for the year ended December 31, 1996 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, 1996. 11 PART II ITEM 5. MARKET FOR UNITS OF THE TRUST AND RELATED SECURITY HOLDER MATTERS The information under "Units of Beneficial Interest" at page 2 of the Trust's Annual Report to security holders for the year ended December 31, 1996, is herein incorporated by reference. ITEM 6. SELECTED FINANCIAL DATA
FOR THE YEAR ENDED DECEMBER 31, ----------------------------------------------------------- 1996 1995 1994 1993 1992 ----------- ----------- ----------- ----------- ----------- Royalty income(1)....... $41,236,424 $15,156,292 $23,280,188 $37,576,121 $32,494,453 Distributable income.... 37,803,167 13,790,101 22,632,493 36,760,797 31,705,994 Distributable income per Unit................... 0.811072 0.295867 0.485584 0.788710 0.680257 Distributions per Unit.. 0.811072 0.295867 0.485584 0.788710 0.680257 Total assets, December 31..................... 65,935,976 70,554,982 75,531,405 82,701,203 90,372,116
- -------- (1) The royalty income distributions for 1992 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 1996 and 1995" at pages 6, 7, and 9 of the Trust's Annual Report to security holders for the year ended December 31,1996, are herein incorporated by reference. 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, 1996, are herein incorporated by reference. ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None. 12 PART III ITEM 10 DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The Trust has no directors or executive officers. The Trustee is a corporate trustee which may be removed, with or without cause, at a meeting of the Unit holders, by the affirmative vote of the holders of a majority of all the Units then outstanding. ITEM 11. EXECUTIVE COMPENSATION During the year ended December 31, 1996, the Trustee received total remuneration as follows:
NAME OF INDIVIDUAL OR NUMBER OF PERSONS IN GROUP CAPACITIES IN WHICH SERVED CASH COMPENSATION ------------------------------- -------------------------- ----------------- Bank One, Texas, N.A...... Trustee $189,219(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, 1996, information with respect to each person known to own beneficially more than 5% of the outstanding Units of the Trust:
AMOUNT AND NATURE NAME AND ADDRESS OF BENEFICIAL OWNERSHIP PERCENT OF CLASS ---------------- ----------------------- ---------------- Fund American Enterprises Holdings, Inc. (1)............................. 10,994,876 Units 23.6% The 1820 House, Main Street Norwich, Vermont 05055 Capital Guardian Trust Company (2).... 4,004,800 Units 8.6% 333 South Hope Street, 52nd Floor Los Angeles, California 90071
- -------- (1) This information was provided to the Securities and Exchange Commission and to the Trust in a Form 4 dated July 9, 1996, filed with the Securities and Exchange Commission by Fund American Enterprises Holdings, Inc. ("FAEH") which indicated that these Units were owned by FAEH. According to such Form 4, FAEH owns 157,215 Units directly and 10,837,661 Units indirectly as follows: 10,759,876 Units indirectly through its wholly-owned subsidiary Fund American Enterprises, Inc. ("FAE") and 77,785 Units indirectly through its wholly-owned subsidiary White Mountain Holdings, Inc. and certain of its wholly-owned subsidiaries. The Form 4 filed by FAEH with the Securities and Exchange Commission may be reviewed for more detailed information concerning the matters summarized herein. (2) This information was provided to the Securities and Exchange Commission and to the Trust in Amendment 3 to Schedule 13G dated February 12, 1997, filed jointly with the Securities and Exchange Commission by The Capital Group Companies, Inc. ("Capital Group") and Capital Guardian Trust Company ("Capital Guardian"). Capital Guardian is a bank wholly-owned operating subsidiary of Capital Group. Capital Guardian exercised investment discretion with respect to the 4,004,800 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 3,249,800 Units and sole dispositive power over 4,004,800 Units. The Amendment 3 to Schedule 13G filed by Capital Group and Capital Guardian with the Securities and Exchange Commission may be reviewed for more detailed information concerning the matters summarized herein. 13 (b) Security Ownership of Management. The Trustee owns beneficially no securities of the Trust. In various fiduciary capacities, Bank One, Texas, NA owned, as of December 31, 1996, an aggregate of 23,672 Units with the sole right to vote 7,520 of these Units and shared right to vote 16,152 of these Units. Such Bank 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, NA. ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Trust has no directors or executive officers. See Item 11 for the remuneration received by the Trustee during the year ended December 31, 1996 and Item 12(b) for information concerning Units owned by Bank One, Texas, NA in various fiduciary capacities. 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, 1996: 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, NA), as Trustee, heretofore filed as Exhibit 4(a) to the Trust's Annual Report on Form 10-K to the Securities and Exchange Commission for the fiscal year ended December 31, 1980, is incorporated herein by reference.* (b) --Net Overriding Royalty Conveyance from Southland Royalty Company to The Forth Worth National Bank (now Bank One, Texas, NA), as Trustee, dated November 3, 1980 (without Schedules), heretofore filed as Exhibit 4(b) to the Trust's Annual Report on Form 10-K to the Securities and Exchange Commission 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, 1996.** (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, NA, 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, 1996, no reports on Form 8-K were filed with the Securities and Exchange Commission by the Trust. 14 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, NA TRUSTEE OF THE SAN JUAN BASIN ROYALTY TRUST /s/ Lee Ann Anderson By: _________________________________ (Lee Ann Anderson) Vice President Date: March 31, 1997 (The Trust has no directors or executive officers) 15 EX-13 2 ANNUAL REPORT EXHIBIT 13 SAN JUAN BASIN ROYALTY TRUST 1996 ANNUAL REPORT & FORM 10-K ------------------ The powerful energy of natural gas took a very long time to get to the surface of the beautiful San Juan Basin of New Mexico. Accompanying the text in this report is an artist's view of that eons-old process. THE TRUST The principal asset of the San Juan Basin Royalty Trust (the "Trust") consists of a 75% net overriding royalty interest carved out of certain of Southland Royalty Company's ("Southland Royalty") oil and gas leasehold and royalty interests in the San Juan Basin of northwestern New Mexico. 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, 1995, to December 31, 1996, quarterly high and low sales prices and the aggregate amount of monthly distributions per Unit paid each quarter were as follows:
1996 HIGH LOW DISTRIBUTION - ----------------------------------------------- First Quarter $6.875 $5.875 $.084239 Second Quarter 6.500 5.625 .063143 Third Quarter 7.500 6.000 .488979 Fourth Quarter 8.625 6.125 .174711 -------- Total for 1996 $.811072 ======== 1995 HIGH LOW DISTRIBUTION - ----------------------------------------------- First Quarter $7.375 $5.875 $.090595 Second Quarter 7.250 5.625 .108430 Third Quarter 7.000 5.875 .071482 Fourth Quarter 6.875 5.750 .025360 -------- Total for 1995 $.295867 ========
At December 31, 1996, 46,608,796 Units outstanding were held by 2,580 Unit holders of record. The following table presents information relating to the distribution of ownership Units:
TYPE OF NUMBER OF UNIT HOLDERS UNIT HOLDERS UNITS HELD - --------------------------------------------------------- Individuals 2,031 3,475,705 Fiduciaries 477 882,299 Institutions 55 942,934 Brokers, Dealers and Nominees 8 39,653,276 Corporations and Partnerships 7 1,614,512 Miscellaneous 2 40,070 ----- ---------- Total 2,580 46,608,796 ===== ==========
2 TO UNIT HOLDERS We are pleased to present the 1996 Annual Report of the San Juan Basin Royalty Trust. The report includes a copy of the Trust's Annual Report on Form 10-K filed with the Securities and Exchange Commission for the year ended December 31, 1996, without exhibits. The Form 10-K contains important information concerning the Trust's properties, including the oil and gas reserves attributable to the net overriding royalty interest owned by the Trust. 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 Texas American Bank/Fort Worth, N.A. 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. Under the Trust Indenture, Bank One, Texas, NA (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 distributed to Unit holders for the year 1996 was $37,803,167 or $.811072 per Unit. This distributable income consisted of Royalty Income of $41,236,424 plus interest income of $76,346 less administrative expenses of $3,509,603. $19,822,005 of the 1996 distributable income is attributable to the settlement of litigation involving the Trustee and BROG. For further information regarding the litigation settlement, see Note 5 to the accompanying Financial Statements. 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, 1997, and for the year ending December 31, 1997. Unit holders owning Units in nominee name may obtain monthly tax information from the Trustee upon request. Bank One, Texas, NA, Trustee By: /s/ LEE ANN ANDERSON Lee Ann Anderson Vice President 3 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 "Trust Properties"). The Trust Properties contain 151,900 (119,000 net) producing acres and 3,180 (960 net) economic wells, including dual completions. The Trust 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, 1996, the production index for the San Juan Basin properties is estimated to be approximately 10.1 years. During 1988, a drilling program was initiated involving development of Fruitland Coal gas reserves. Wells drilled in the Fruitland Coal range in depth from 2,500 to 3,500 feet on a 320acre 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 filed 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. From 1988 through December 31, 1996, BROG has participated in the completion of 113 gross (75.05 net) and recompletions of 110 gross (65.96 net) coal seam wells on Trust Properties. At December 31, 1996, 167 coal seam wells had been connected to pipeline facilities. During 1996, these coal seam wells produced a total of approximately 16,250,517 MMBtu of gas from the Trust Properties, which was sold at an average price of $1.02 per MMBtu. 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 qualifying coal seam formation which are later completed into such formation, also qualifies for the tax credit. For 1996 the credit was approximately $1.03 per MMBtu. During 1995, potential Section 29 tax credits of approximately $1.02 per Unit were generated for Trust Unit holders from production from coal seam wells. During 1996, BROG incurred approximately $7,223,281 of capital expenditures for the drilling and completion of 14 gross (1.50 net) conventional wells, recavition of 17 gross (5.63 net) coal seam wells, recompleting 4 gross (.16 net) conventional wells as coal seam wells, recompleting 9 gross (5.93 net) conventional wells and other maintenance activities. There was 1 gross (.05 net) coal seam well, 3 gross (.14 net) coal seam recompletions and 17 gross (1.96 net) conventional wells in progress at December 31, 1996. During 1995, Southland Royalty participated in the completion of 24 gross (11.41 net) conventional wells, drilling and completion of 5 gross (2.54 net) coal seam wells, recompleting 38 gross (8.61 net) conventional wells and other maintenance activities and facilities costs at a cost of $6,560,276. Due to the size of the coal seam drilling program in the San Juan Basin during the last several years by various operators, there was more gas deliverability than available pipeline capacity. Consequently, these properties produced only 20.4 Bcf during 1991. 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 40.7 in 1996. BROG has advised the Trustee that mainline capacity out of the San Juan Basin is estimated at 3.05 Bcf per day for El Paso Natural Gas Pipeline Company and approximately 1.51 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. Based on existing geological and pricing information, there are approximately 72 net conventional wells remaining to be drilled on the Trust Properties. Proved undeveloped reserves have been assigned to these wells. BROG has advised the Trust that its 1997 capital expense estimate for Trust working interests is estimated to be $1.7 million. Fruitland Coal is estimated to be approximately 16% of the total and the remainder would be conventional projects, including 43 new drill locations. There are 13 other projects planned, half of which would involve conventional locations. 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. Gas production from the Trust Properties is sold in both interstate and intrastate commerce. For a further discussion of gas pricing, gas purchasers, gas production and regulatory matters affecting gas production see Item 2 in the accompanying Form 10-K. 4 Millenniums of intense heat and pressure on fossilized marine life and other organic matter formed the San Juan Basin's natural gas and petroleum resources. 5 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, 1996, distributable income increased to $37,803,167 from $13,790,101 distributed in 1995. The increase was primarily attributable to the payment by Burlington to the Trust in September 30, 1996, of $19,822,005 in settlement of litigation involving Bank One, Texas, NA, as Trustee and BROG (the "Litigation"). Interest income increased from $31,978 in 1995 to $76,346 in 1996 primarily due to increased funds available for investment. The Trustee announced on September 4, 1996, the settlement of the Litigation. The Litigation, which was filed in the state district court of Santa Fe County, New Mexico, 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 Trust Properties. BROG denied and continues to deny the allegations made against it in the Litigation, but the parties agreed to settle the Litigation as outlined below. 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 Trust Properties. Agreement was also reached regarding marketing arrangements for the sale of Trust gas, oil and natural gas liquids products going forward as follows: 1. BROG's preexisting contract with a third-party purchaser as pertains to base load gas volumes in the firm amount of 45,000 MMBtu per day will remain effective for a period of one year from July 1, 1996. Negotiations for the sale of these volumes after June 30, 1997, will be entered into prior to the expiration of the primary term of that contract; 2. The remaining volumes of Trust gas will be marketed by an independent marketer, El Paso Energy Marketing Company ("El Paso"), a subsidiary of El Paso Energy Corporation, beginning October 1, 1996, under an arrangement which provides for a sharing of amounts, if any, earned in excess of established gas price thresholds. El Paso's compensation for its marketing services consists solely of its proportionate part of any amount for which the gas sold in excess of the thresholds. BROG's contract with El Paso is for a two-year term beginning October 1, 1996, subject to renewal by agreement of the parties; 3. 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 4. The marketer of the Trust gas will have 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 may utilize BROG's contractual rights for delivery on the El Paso Natural Gas Company pipeline to pipelines in West Texas for up to 13,333 MMBtu per day of gas produced from the Trust Properties for a period of one year commencing October 1, 1996. Confidentiality agreements with purchasers of the gas produced from the Trust 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 of the marketer to compete effectively in the marketplace for the sale of gas produced from the Trust Properties. 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. Gas and oil sales attributable to the Royalty for the past five years, excluding portions attributable to the litigation settlement proceeds (See Note 6 to accompanying Financial Statements), are summarized in the following table:
1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------ Gas - Mcf 17,927,785 13,331,758 15,459,542 23,895,506 13,984,645 Average Price (per Mcf) $1.30 $1.25 $1.66 $1.70 $1.57 Oil - Bbls 36,792 29,424 36,769 51,921 41,087 Average Price (per Bbl) $19.64 $14.43 $13.09 $15.58 $17.65
6 Due to the increase in the average price of gas in the first quarter of 1993, the average price for the year increased. Gas prices plummeted in 1995. Since the oil and gas sales attributable to the Royalty are based on an allocation formula that is dependent on such factors as price and cost, the production amounts do not provide a meaningful comparison. Total gas and oil production from the properties from which the Royalty was carved for the five years ended December 31, 1996, were as follows:
1996 1995 1994 1993 1992 - -------------------------------------------------------------------------- Gas - 40,738,422 34,222,189 34,222,189 40,736,391 26,642,265 Mcf per day 111,307 94,211 93,759 111,607 72,993 Oil - Bbls 83,552 75,014 84,648 88,466 79,600 Bbls per day 228 206 232 242 218
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 properties from which the Royalty was carved 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. Royalty Income for the five years ended December 31, 1996, was determined as shown in the following table:
1996 1995 1994 1993 1992 - ------------------------------------------------------------------------------------------------------------ GROSS PROCEEDS FROM THE SOUTHLAND ROYALTY PROPERTIES FROM WHICH THE TRUST'S OVERRIDING ROYALTY WAS CARVED: Gas $51,865,730 $41,483,305 $54,375,586 $69,266,623 $41,961,599 Oil 1,638,753 1,084,262 1,140,738 1,384,468 1,409,179 Other -0- 2,952 -0- -0- -0- 1990 Litigation Settlement -0- -0- -0- -0- 16,118,174 ----------- ----------- ----------- ---------- ----------- Total 53,504,483 42,570,159 55,498,324 70,651,091 59,488,952 ----------- ----------- ----------- ---------- ----------- LESS PRODUCTION COSTS: Capital Costs 7,223,281 6,560,277 9,409,462 3,988,136 2,530,833 Severance Tax - Gas 5,654,831 4,694,750 5,864,834 6,543,615 3,696,172 Severance Tax - Oil 176,379 115,474 117,028 153,072 155,663 Severance Tax - Other 59,089 117 -0- -0- -0- Severance Tax - Litigation -0- -0- -0- -0- 356,944 Lease Operating Expenses 11,838,345 10,991,152 9,066,750 9,864,773 9,423,403 ----------- ----------- ----------- ---------- ----------- Total 24,951,925 22,361,770 24,458,074 20,549,596 16,163,015 ----------- ----------- ----------- ---------- ----------- Net Profits 28,552,558 20,208,389 31,040,250 50,101,495 43,325,937 Royalty Percentage 75% 75% 75% 75% 75% Royalty Income $21,414,419 $15,156,292 $23,280,188 $37,576,121 $32,494,453 =========== =========== =========== =========== ===========
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 properties from which the Royalty was carved for the year ended December 31, 1996, amounted to $7,223,281 versus $6,560,277 for 1995. The increase was primarily attributable to increased drilling activity. The litigation settlement and the related severance taxes for 1992 pertain to The Public Service Company of New Mexico litigation which was settled during 1990. 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. See Note 5 to the accompanying Financial Statements. Monthly operating costs in 1996 averaged approximately $955,000, which is higher than the $876,000 average in 1995. 7 Coal seams lying relatively near the surface of the earth yield much of the natural gas produced in the San Juan Basin. 8 RESULTS OF THE 4TH QUARTERS OF 1996 AND 1995 Distributable income for the three months ended December 31, 1996, totaled $8,143,076 ($.174711 per Unit) as compared to $1,182,038 ($.025361 per Unit) for the quarter ended December 31, 1995. The amount distributed in the fourth quarter of 1996 was higher than that of 1995 primarily because of the higher average price of gas sold. 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, 1996 and 1995 were as follows:
1996 1995 - ---------------------------------------------------------- PROPERTIES FROM WHICH THE ROYALTY WAS CARVED Gas Mcf 10,535,177 8,929,852 Average Price (per Mcf) $1.64 $.98 Oil - Bbls 19,460 17,681 Average Price (per Bbl) $21.06 $14.72 ATTRIBUTABLE TO THE ROYALTY Gas - Mcf 5,478,137 1,864,559 Oil - Bbls 10,260 17,681
The average price of gas increased in the fourth quarter of 1996 primarily due to increases in spot prices. The average price of oil increased compared to the prior year because of increases in the posted prices. Gas production increased primarily due to increased coal seam production and demand from gas purchasers. During the fourth quarter of 1996, coal seam production from the properties from which the Royalty was carved averaged 1,728,000 Mcf per month compared to 1,173,000 Mcf per month during the fourth quarter of 1995. Capital costs for the fourth quarter of 1996 totaled $1,996,490 compared to $2,413,744 during the same period of 1995. The decrease was due to a decrease in drilling activity in the fourth quarter of 1996. Lease operating costs for the fourth quarter of 1996 averaged $926,000 per month in the fourth quarter compared to $1,025,000 per month in the fourth quarter of 1995. 9 SAN JUAN BASIN ROYALTY TRUST
STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS DECEMBER 31, 1996 AND 1995 1996 1995 - --------------------------------------------------------------------------------------------------- ASSETS Cash and Short-term Investments $ 3,127,828 $ 421,446 Net Overriding Royalty Interest in Producing Oil and Gas Properties - Net (Notes 2 and 3) 62,808,148 70,133,536 ------------ ------------ $ 65,935,976 $ 70,554,982 ============ ============ LIABILITIES AND TRUST CORPUS Distribution Payable to Unit Holders $ 3,127,828 $ 421,446 Contingencies (Note 5) - - Trust Corpus - 46,608,796 Units of Beneficial Interest Authorized and Outstanding 62,808,148 70,133,536 ------------ ------------ $ 65,935,976 $ 70,554,982 ============ ============
STATEMENTS OF DISTRIBUTABLE INCOME FOR THE THREE YEARS ENDED DECEMBER 31, 1996 1996 1995 1994 - ------------------------------------------------------------------------------------------------------ Royalty Income (Notes 2, 3 and 5) $ 41,236,424 $ 15,156,292 $ 23,280,188 Interest Income 76,346 31,978 38,129 ------------ ------------ ------------ 41,312,770 15,188,270 23,318,317 Expenditures- General and Administrative 3,509,603 1,398,169 685,824 ------------ ------------ ------------ Distributable Income $ 37,803,167 $ 13,790,101 $ 22,632,493 ------------ ------------ ------------ Distributable Income per Unit (46,608,796 Units) $ .811072 $ .295867 $ .485584 ============ ============ ============ STATEMENTS OF CHANGES IN TRUST CORPUS FOR THE THREE YEARS ENDED DECEMBER 31, 1996 1996 1995 1994 - --------------------------------------------------------------------------------------------------- Trust Corpus, Beginning of Period $ 70,133,536 $ 74,942,040 $ 79,898,032 Amortization of Net Overriding Royalty Interest (Notes 2 and 3) (7,325,388) (4,808,504) (4,955,992) Distributable Income 37,803,167 13,790,101 22,632,493 Distributions Declared (37,803,167) (13,790,101) (22,632,493) ------------ ------------ ------------ Trust Corpus, End of Period $ 62,808,148 $ 70,133,536 $ 74,942,040 ============ ============ ============
The accompanying Notes to Financial Statements are an integral part of this statement. 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, NA ("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 is 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, 1996 and 1995 aggregated $70,467,380 and $63,141,992, 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 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. 11 [_] SAN JUAN BASIN [_] GAS FIELDS [_] OIL FIELDS [_] LEASEHOLD ACREAGE [_] MINERAL ACREAGE 12 4. FEDERAL INCOME TAXES For Federal income tax purposes, the Trust constitutes a taxed 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 concerning 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 qualifying coal seam formation which are later completed into such formation, also qualifies for the tax credit. This tax credit was approximately $1.03 per MMBtu for the year 1996 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. COMMITMENTS AND CONTINGENCIES On June 4, 1992, the Trustee filed suit against MOI and Southland in the state district court in Rio Arriba County, New Mexico, Cause No. RA 92-1211(C). MOI and Southland were the operators of the Trust 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"). In a decision filed August 8, 1994, the Supreme Court of New Mexico ruled that venue was not proper in Rio Arriba County and remanded the case for dismissal without prejudice to its refiling. In its ruling, the Supreme Court of New Mexico also ruled that venue was proper in Santa Fe County, New Mexico. Such decision did not relate to merits of the Trust's claims. The Trustee refiled the lawsuit in Santa Fe County, New Mexico on August 31, 1994, in Cause No. SF 94-1982(C). 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 "Trust Properties"). The claims asserted on behalf of the Trust in the Santa Fe County, New Mexico, 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 Trust Properties. In response to the Trustee's lawsuit, Southland filed suit on August 7, 1992 against the Trustee in Probate Court in Tarrant County, Texas, Cause No. 92-1927-2. Non-binding mediation, which had been ongoing with regard to the lawsuit filed in Santa Fe County, New Mexico, was not successful in resolving the claims asserted by the Trust. On September 4, 1996, the Trustee announced the settlement of the litigation (the "Litigation"). The Litigation was dismissed on September 12, 1996. BROG has 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 13 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 Trust Properties. Agreement was also reached regarding marketing arrangements for the sale of Trust gas, oil and natural gas liquids products going forward as follows: 1) BROG's pre-existing contract with a third-party purchaser as pertains to baseload gas volumes in the firm amount of 45,000 MMBtu per day will remain effective for a period of one year from July 1, 1996. Negotiations for the sale of these volumes after June 30, 1997, will be entered into prior to the expiration of the primary term of that contract; 2) 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, under an arrangement which provides for a sharing of amounts, if any, earned in excess of established gas price thresholds. El Paso's compensation for its marketing services consists solely of its proportionate part of any amounts for which the gas is sold in excess of the thresholds. BROG's contract with El Paso is for a two year term beginning October 1, 1996, subject to renewal by agreement of the parties; 3) 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 4) 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 may 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 Trust Properties for a period of one year commencing October 1, 1996. Confidentiality agreements with purchasers of gas produced from the Trust 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 Trust Properties. The $19,822,005 (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 Trust 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 wellhead 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 properties from which the Royalty was carved. To continue to maximize production and revenues from Trust 14 properties, Southland again informed the Trustee that it negotiated an agreement with Sunterra 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 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. Southland also advised the Trust 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 Trust has further been advised by Southland that MOTI negotiated an agreement with Gas Company providing for transportation service on Gas Company's Albuquerque mainline. This agreement was effective on the closing date of the sale of Gas Company's gathering and processing facilities to Williams. This transportation agreement will be necessary to deliver volumes of gas behind the Lybrook processing plant to mainline delivery points. Southland further informed the Trust that on September 13, 1994, MOTI entered into a gas sales agreement with Gas Company for the five winter periods beginning November 1, 1995, and ending March 31, 2000. MOTI purchased the gas supplied for this sale from MOI producing affiliates and third party sellers. Sales were based on a monthly published index. BROG has informed the Trust that as a result of the Litigation (as hereinafter defined), no gas produced from the properties from which the Royalty was carved will be applied in performance of such agreement with Gas Company. It is the understanding of the Trustee that Gas Company is now known as PNM Gas Services. While it is impossible to determine the exact economic value to be derived under these agreements, Southland has advised the Trust that it considers the terms of these agreements to be favorable, and of substantial additional value. 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, 1996 (in thousands, except unit amounts):
DISTRIBUTABLE INCOME AND DISTRIBUTABLE DISTRIBUTABLE INCOME 1996 ROYALTY INCOME PER UNIT - --------------------------------------------------------- First Quarter $ 4,708 $ 3,926 $.084239 Second Quarter 4,048 2,943 .063143 Third Quarter 24,135 22,791 .488979 Fourth Quarter 8,345 8,143 .174711 ------- ------- -------- Total $41,236 $37,803 $.811072 ======= ======= ======== 1995 - --------------------------------------------------------- First Quarter $ 4,476 $ 4,222 $.090595 Second Quarter 5,458 5,054 .108430 Third Quarter 3,542 3,332 .071482 Fourth Quarter 1,680 1,182 .025360 ------- ------- -------- Total $15,156 $13,790 $.295867 ======= ======= ========
15 INDEPENDENT AUDITOR'S REPORT BANK ONE, TEXAS, NA 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, 1996 and 1995, and the related statements of distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1996. 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, 1996 and 1995 and the distributable income and changes in trust corpus for each of the three years in the period ended December 31, 1996 on the basis of accounting described in Note 3. /s/ DELOITTE & TOUCHE LLP Deloitte & Touche LLP Fort Worth, Texas March 25, 1997 San Juan Basin Royalty Trust Bank One, Texas, NA, Trustee Post Office Box 2604 Fort Worth, Texas 76113 Auditors Deloitte & Touche LLP Fort Worth, Texas Legal Counsel Vinson & Elkins L.L.P Dallas, Texas Tax Counsel Butler & Binion, L.L.P. Houston, Texas Transfer Agent Harris Trust & Savings Bank Chicago, Illinois 16 EX-23 3 CAWLEY CONSENT EXHIBIT 23 [PASTE-UP LETTERHEAD HERE] March 26, 1997 San Juan Basin Royalty Trust Bank One, Texas 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, 1996 and in the San Juan Basin Royalty Trust Annual Report for the year ended December 31, 1996 based on reserve reports dated March 25, 1997 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 OF SAN JUAN BASIN ROYALTY TRUST AS OF DECEMBER 31, 1996, AND THE RELATED CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME AND CHANGES IN TRUST CORPUS FOR THE TWELVE- MONTH PERIOD ENDED DECEMBER 31, 1996. 12-MOS DEC-31-1996 DEC-31-1996 3,127,828 0 0 0 0 3,127,828 133,275,528 70,467,380 65,935,976 3,127,828 0 0 0 0 62,808,148 65,935,976 0 41,312,770 0 0 3,509,603 0 0 37,803,167 0 37,803,167 0 0 0 37,803,167 0 0
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